U.S. patent application number 15/085445 was filed with the patent office on 2016-09-15 for robust integrated process for conversion of waste plastics to final petrochemical products.
The applicant listed for this patent is Sabic Global Technologies, B.V.. Invention is credited to Mohammad JAVEED, Ravichander NARAYANASWAMY, Krishna Kumar RAMAMURTHY, Alexander STANISLAUS.
Application Number | 20160264874 15/085445 |
Document ID | / |
Family ID | 56879304 |
Filed Date | 2016-09-15 |
United States Patent
Application |
20160264874 |
Kind Code |
A1 |
NARAYANASWAMY; Ravichander ;
et al. |
September 15, 2016 |
Robust Integrated Process for Conversion of Waste Plastics to Final
Petrochemical Products
Abstract
A robust integrated process for the conversion of waste plastics
to high value products. The robust integrated process allows for
operation with a single hydroprocessing reactor which provides
simultaneous hydrogenation, dechlorination, and hydrocracking of
components of a hydrocarbon stream to specifications which meet
steam cracker requirements, with the option to further dechlorinate
the treated hydrocarbon stream in a polishing zone.
Inventors: |
NARAYANASWAMY; Ravichander;
(Bengaluru, IN) ; RAMAMURTHY; Krishna Kumar;
(Bengaluru, IN) ; STANISLAUS; Alexander;
(Bangalore, IN) ; JAVEED; Mohammad; (Bengaluru,
IN) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Sabic Global Technologies, B.V. |
BERGEN OP ZOOM |
|
NL |
|
|
Family ID: |
56879304 |
Appl. No.: |
15/085445 |
Filed: |
March 30, 2016 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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PCT/IB2016/051137 |
Mar 1, 2016 |
|
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15085445 |
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62201676 |
Aug 6, 2015 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
C10B 53/07 20130101;
C10G 1/10 20130101; C10G 47/00 20130101; C10G 45/08 20130101; C10G
9/36 20130101; C10G 2300/201 20130101; C10G 1/002 20130101; C10G
69/06 20130101; C10G 45/02 20130101; C10G 2300/301 20130101 |
International
Class: |
C10G 1/10 20060101
C10G001/10; C10G 69/06 20060101 C10G069/06; C10B 53/07 20060101
C10B053/07; C10G 1/00 20060101 C10G001/00 |
Foreign Application Data
Date |
Code |
Application Number |
Mar 10, 2015 |
IN |
1171CHE2015 |
Claims
1. A process for converting waste plastics to a high value product
comprising: converting the waste plastics to a hydrocarbon stream
in a liquid phase, wherein the hydrocarbon stream comprises one or
more chloride compounds in a concentration of 5 ppm or more based
on a total weight of the hydrocarbon stream; contacting the
hydrocarbon stream with a first hydroprocessing catalyst in the
presence of hydrogen to yield a first hydrocarbon product
comprising C.sub.1 to C.sub.4 gases and C.sub.5+ liquid
hydrocarbons; recovering the C.sub.5+ liquid hydrocarbons in a
treated hydrocarbon stream from the first hydrocarbon product,
wherein the treated hydrocarbon stream comprises the one or more
chloride compounds in a concentration of 3 to 5 ppm based on a
total weight of the treated hydrocarbon stream; dechlorinating the
treated hydrocarbon stream to yield a polished hydrocarbon stream
comprising one or more chloride compounds in a concentration of
less than 3 ppm based on a total weight of the polished hydrocarbon
stream; and feeding the treated hydrocarbon stream or polished
hydrocarbon stream to a steam cracker to yield the high value
product, wherein the treated hydrocarbon stream or polished
hydrocarbon stream meets steam cracker feed requirements for
chloride content, olefin content, and boiling end point.
2. The process of claim 1, wherein the step of dechlorinating
comprises contacting the treated hydrocarbon stream with a second
hydroprocessing catalyst in the presence of hydrogen to yield a
second hydrocarbon product.
3. The process of claim 1, wherein the step of dechlorinating
comprises removing at least a portion of the one or more chloride
compounds via adsorptive dechlorination to yield the polished
hydrocarbon stream.
4. The process of claim 1, wherein the polished hydrocarbon stream
comprises the one or more chloride compounds in a concentration of
less than 1 ppm based on the total weight of the polished
hydrocarbon stream, wherein the hydrocarbon stream comprises the
one or more chloride compounds in a concentration of greater than
200 ppmw based on a total weight of the hydrocarbon stream.
5. The process of claim 1, wherein the hydrocarbon stream comprises
one or more olefins, wherein the treated hydrocarbon stream
comprises the one or more olefins in a concentration of less than 1
wt. % based on the total weight of the treated hydrocarbon stream,
and wherein the one or more olefins are present in the hydrocarbon
stream in a concentration of 20 wt % or more based on the total
weight of the hydrocarbon stream.
6. The process of claim 1, wherein the hydrocarbon stream comprises
heavy hydrocarbon molecules, and further comprising: hydrocracking
at least a portion of the heavy hydrocarbon molecules during the
step of contacting the hydrocarbon stream with a first
hydroprocessing catalyst.
7. The process of claim 1, further comprising: before the step of
contacting the hydrocarbon stream with a first hydroprocessing
catalyst, contacting a catalyst activating stream comprising one or
more sulphides with the first hydroprocessing catalyst, and wherein
the one or more sulphides are in an amount of about 0.5 wt % to 5
wt % based on the total weight of the catalyst activating
stream.
8. The process of claim 1, wherein the one or more sulphides of the
hydrocarbon stream are present in a concentration of about 2 wt %
based on the total weight of the hydrocarbon stream.
9. The process of claim 1, wherein the step of contacting the
hydrocarbon stream with a first hydroprocessing catalyst is
performed at a weight hourly space velocity of 0.1 to 10 hr.sup.-1,
at a hydrogen to hydrocarbon ratio of 10 to 3,000 NL/L, and at a
pressure of 1 to 200 barg.
10. The process of claim 1, wherein the first hydroprocessing
catalyst comprises cobalt and molybdenum on an alumina support,
nickel and molybdenum on an alumina support, tungsten and
molybdenum on an alumina support, nickel sulphide, molybdenum
sulphides, a combination of nickel and molybdenum sulphides, or
combinations thereof.
11. The process of claim 10, wherein contacting the hydrocarbon
stream with the first hydroprocessing catalyst comprises:
contacting one or more sulphides contained in or added to the
hydrocarbon stream with the first hydroprocessing catalyst.
12. The process of claim 2, wherein the second hydroprocessing
catalyst comprises cobalt and molybdenum on an alumina support,
nickel and molybdenum on an alumina support, tungsten and
molybdenum on an alumina support, nickel sulphide, molybdenum
sulphides, a combination of nickel and molybdenum sulphides, or
combinations thereof.
13. The process of claim 12, wherein contacting the treated
hydrocarbon stream with the second hydroprocessing catalyst
comprises: contacting one or more chloride compounds contained in
the treated hydrocarbon stream with the second hydroprocessing
catalyst.
14. The process of claim 1, wherein the high value products are
ethylene, propylene, butene, butadiene, aromatic compounds, or
combinations thereof.
15. The process of claim 1, wherein the step of converting
comprises: subjecting the waste plastics to a pyrolysis process to
produce one or more of plastic pyrolysis oil and tire pyrolysis oil
in the hydrocarbon stream.
16. The process of claim 1, wherein recovering a treated
hydrocarbon stream from the first hydrocarbon product comprises:
separating the first hydrocarbon product into a treated product
from a first chlorine-containing gas in a first separator; and
flowing the treated product in the treated hydrocarbon stream from
the first separator to an adsorption unit or to a steam
cracker.
17. The process of claim 2, wherein the step of dechlorinating
further comprises: separating the second hydrocarbon product into a
polished product and a second chlorine-containing gas in a second
separator; and flowing the polished product in the polished
hydrocarbon stream from the second separator to a steam
cracker.
18. The process of claim 1, wherein the step of converting the
waste plastics to a hydrocarbon stream in a liquid phase is
performed in the presence of a head space purge gas fed to a
pyrolysis unit, wherein the head space purge gas comprises
hydrogen, nitrogen, steam, product gases, or combinations
thereof.
19. The process of claim 1, further comprising: converting the
waste plastics to C.sub.1 to C.sub.4 pyrolysis gases, wherein one
or more of the C.sub.1 to C.sub.4 pyrolysis gases, the C.sub.1 to
C.sub.4 gases yielded in the step of contacting, and C.sub.1 to
C.sub.4 gases yielded in the step of dechlorinating is fed to the
steam cracker.
20. The process of claim 1, wherein the step of contacting includes
simultaneous i) dechlorination of the hydrocarbon stream such that
the treated hydrocarbon stream comprises one or more chloride
compounds in a concentration less than 1 ppmw based on the total
weight of the treated hydrocarbon stream, ii) hydrogenation of the
hydrocarbon stream such that the treated hydrocarbon stream
comprises one or more olefins in a concentration less than 1 wt %
based on the total weight of the treated hydrocarbon stream, and
iii) reduction of heavy hydrocarbon molecules of the hydrocarbon
stream.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] The present application is a continuation of and claims
priority to International Application No. PCT/IB2016/051137 filed
Mar. 1, 2016, entitled "A Robust Integrated Process for Conversion
of Waste Plastics to Final Petrochemical Products," which claims
priority to U.S. Provisional Application No. 62/201,676 filed on
Aug. 6, 2015, entitled "A Robust Integrated Process for Conversion
of Waste Plastics to Final Petrochemical Products," and Indian
Provisional Application No. 1171/CHE/2015 filed Mar. 10, 2015
entitled "A Robust Integrated Process for Conversion of Waste
Plastics to Final Petrochemical Products," which applications are
incorporated by reference herein in their entirety.
TECHNICAL FIELD
[0002] The present disclosure relates to the treatment of
hydrocarbon streams resulting from pyrolysis of waste plastics for
use in downstream processes.
BACKGROUND
[0003] Waste plastics contain polyvinylchloride (PVC). Through a
pyrolysis process, waste plastics can be converted to gas and
liquid products. These liquid products contain paraffins,
i-paraffins (iso-paraffins), olefins, naphthenes, and aromatic
components along with organic chlorides in concentrations of
hundreds of ppm. As such, the liquid products of a pyrolysis
process (pyrolysis oils) can be used as a feedstock for steam
crackers partly replacing naphtha used in these units. However,
pyrolysis oils do not meet the steam cracker feed specification
requirements of chloride levels less than 3 ppm, olefin content
less than 1 wt %, and boiling end point requirements of 370.degree.
C.
SUMMARY
[0004] Disclosed herein is a process for converting waste plastics
to a high value product comprising converting the waste plastics to
a hydrocarbon stream in a liquid phase, wherein the hydrocarbon
stream comprises one or more chloride compounds in a concentration
of 5 ppm or more based on a total weight of the hydrocarbon stream,
contacting the hydrocarbon stream with a first hydroprocessing
catalyst in the presence of hydrogen to yield a first hydrocarbon
product comprising C.sub.1 to C.sub.4 gases and C.sub.5+ liquid
hydrocarbons, recovering the C.sub.5+ liquid hydrocarbons in a
treated hydrocarbon stream from the first hydrocarbon product,
wherein the treated hydrocarbon stream comprises the one or more
chloride compounds in a concentration of 3 to 5 ppm based on a
total weight of the treated hydrocarbon stream, dechlorinating the
treated hydrocarbon stream to yield a polished hydrocarbon stream
comprising one or more chloride compounds in a concentration of
less than 3 ppm based on a total weight of the polished hydrocarbon
stream, and feeding the treated hydrocarbon stream or polished
hydrocarbon stream to a steam cracker to yield the high value
product, wherein the treated hydrocarbon stream or polished
hydrocarbon stream meets steam cracker feed requirements for
chloride content, olefin content, and boiling end point.
BRIEF DESCRIPTION OF THE DRAWINGS
[0005] FIG. 1 illustrates a hydroprocessing system for converting
plastic waste to a high value product by simultaneously
dechlorinating chloride compounds, hydrogenating olefins, and
hydrocracking heavy hydrocarbon molecules contained in a
hydrocarbon stream which contains a pyrolysis oil to levels
suitable for introduction to a steam cracker.
[0006] FIG. 2 illustrates an embodiment of a polishing zone in the
hydroprocessing system.
[0007] FIG. 3 is a graph of the boiling point distribution for a
liquid product of a low severity pyrolysis process, showing
temperature versus mass percent.
[0008] FIG. 4 is a graph of a staged catalyst sulphiding protocol,
showing temperature versus time.
DETAILED DESCRIPTION
[0009] Other than in the operating examples or where otherwise
indicated, all numbers or expressions referring to quantities of
ingredients, reaction conditions, and the like, used in the
specification and claims are to be understood as modified in all
instances by the term "about." Various numerical ranges are
disclosed herein. Because these ranges are continuous, they include
every value between the minimum and maximum values. The endpoints
of all ranges reciting the same characteristic or component are
independently combinable and inclusive of the recited endpoint.
Unless expressly indicated otherwise, the various numerical ranges
specified in this application are approximations. The endpoints of
all ranges directed to the same component or property are inclusive
of the endpoint and independently combinable. The term "X or more"
means that the named component is present in an amount of the value
X, and values which are more than X.
[0010] The terms "a," "an," and "the" do not denote a limitation of
quantity, but rather denote the presence of at least one of the
referenced item. As used herein the singular forms "a," "an," and
"the" include plural referents.
[0011] As used herein, "combinations thereof" is inclusive of one
or more of the recited elements, optionally together with a like
element not recited, e.g., inclusive of a combination of one or
more of the named components, optionally with one or more other
components not specifically named that have essentially the same
function. As used herein, the term "combination" is inclusive of
blends, mixtures, alloys, reaction products, and the like.
[0012] Reference throughout the specification to "an embodiment,"
"embodiments," "another embodiment," "other embodiments,"
"alternative embodiments," "additional embodiments," "some
embodiments," and so forth (e.g., the use of "additionally" and/or
"alternatively" in the context of describing one or more
embodiments), means that a particular element (e.g., feature,
structure, property, and/or characteristic) described in connection
with the embodiment is included in at least an embodiment described
herein, and may or may not be present in other embodiments. In
addition, it is to be understood that the described element(s) can
be combined in any suitable manner in the various embodiments.
[0013] Disclosed herein are embodiments of a process for converting
waste plastics to a high value product. Embodiments of the process
include converting the waste plastics to a hydrocarbon stream in a
liquid phase, converting the waste plastics to a pyrolysis light
gas stream containing C.sub.1 to C.sub.4 hydrocarbons, contacting
the hydrocarbon stream with a hydroprocessing catalyst in the
presence of hydrogen (H.sub.2) to yield a hydrocarbon product,
recovering a treated hydrocarbon stream comprising C5+ hydrocarbons
from the hydrocarbon product, dechlorinating the treated
hydrocarbon stream to yield a polished hydrocarbon stream,
recovering a hydroprocessed light gas stream from the hydrocarbon
product, feeding the treated hydrocarbon stream to a steam cracker
to yield the high value product, feeding the polished hydrocarbon
stream to a steam cracker to yield the high value product, feeding
the pyrolysis light gas stream to the steam cracker, feeding the
hydroprocessed light gas stream to the steam cracker, or
combinations thereof. The treated hydrocarbon stream or polished
hydrocarbon stream meets steam cracker feed requirements. The
pyrolysis light gas stream may be fed to the steam cracker
directly, or after treating the pyrolysis light gas stream in a
scrubbing unit to yield a treated pyrolysis light gas stream which
is subsequently fed to the steam cracker. The hydroprocessed light
gas stream may be fed to the steam cracker directly, or after
treating the hydroprocessed light gas stream in a scrubbing unit to
yield a treated hydroprocessed light gas stream which is
subsequently fed to the steam cracker. Converting the waste
plastics to a hydrocarbon stream in a liquid phase and converting
the waste plastics to a pyrolysis light gas stream containing
C.sub.1 to C.sub.4 hydrocarbons may occur simultaneously via
pyrolysis of the waste plastics.
[0014] Embodiments of the process are described in more detail with
reference to FIG. 1. FIG. 1 illustrates a hydroprocessing system
100 for converting plastic waste to a high value product by
simultaneously dechlorinating chloride compounds, hydrogenating
olefins, and hydrocracking heavy hydrocarbon molecules contained in
a hydrocarbon stream 12 which contains a pyrolysis oil (e.g.,
plastic pyrolysis oil, tire pyrolysis oil) to levels suitable for
introduction to a steam cracker 50. The system 100 includes a
pyrolysis unit 10, a hydroprocessing reactor 20, a separator 30, a
polishing zone 40, and a steam cracker 50. Waste plastic is either
placed in the pyrolysis unit 10 or fed to the pyrolysis unit 10 via
waste plastic stream 1. In the pyrolysis unit 10, the plastic waste
stream is converted via pyrolysis reactions to pyrolysis gases
(e.g., C.sub.1 to C.sub.4 gases) and a liquid pyrolysis oil. The
pyrolysis gases flow from the pyrolysis unit 10 via a pyrolysis
light gas stream 16 directly to the steam cracker 50, or to a
scrubbing unit 60 and then the steam cracker 50. The liquid
pyrolysis oil flows from the pyrolysis unit 10 via hydrocarbon
stream 12. The hydrocarbon stream 12 feeds to the hydroprocessing
reactor 20, and the reaction product effluent of the
hydroprocessing reactor 20 flows from the hydroprocessing reactor
20 in the hydrocarbon product stream 22 to the separator 30. In
separator 30, a treated product (e.g., in gas or liquid form) is
recovered from the hydrocarbon product stream 22 and flows from the
separator 30 via treated hydrocarbon stream 32, with one or more of
sulphur-containing gases and chlorine-containing gases flowing from
the separator 30 in hydroprocessed light gas stream 36. C.sub.1 to
C.sub.4 hydrocarbon gases which are generated in the
hydroprocessing reactor 20 may flow directly to a separator 30,
where the C.sub.1 to C.sub.4 hydrocarbon gases are recovered in a
hydroprocessed light gas stream 36 for flow directly to the steam
cracker 40, to a scrubbing unit 50, or a combination of direct flow
to the steam cracker 40 and flow to the scrubbing unit 50 (e.g., a
portion of the pyrolysis light gas stream bypasses the scrubbing
unit).
[0015] In embodiments where the chloride content of the treated
hydrocarbon product meets steam cracker requirements, the treated
hydrocarbon product in the treated hydrocarbon stream 32 may flow
directly (e.g., without any separations or fractionations of the
treated hydrocarbon stream 32) via bypass stream 34 to a steam
cracker 50, from which high value products flow in stream 52. In
embodiments where the chloride content of the treated hydrocarbon
product does not meet steam cracker feed requirements, the treated
hydrocarbon product may flow in the treated hydrocarbon stream 32
to polishing zone 40, where further dechlorination occurs to yield
the polished hydrocarbon stream 42. The polished hydrocarbon stream
42 may then flow directly (e.g., without any separations or
fractionations of the polished hydrocarbon stream 42) to the stream
cracker 50, from which the high value products flow in stream
52.
[0016] Waste plastics which are loaded into or fed to the pyrolysis
unit 10 via waste plastic stream 1 may include post-consumer waste
plastics. Examples of waste plastics which can be used include
chlorinated plastics (e.g., chlorinated polyethylene),
polyvinylchloride, non-chlorinated plastics (e.g., polyethylene,
polystyrene, polypropylene, copolymers, etc.), or mixtures thereof.
Waste plastics as disclosed herein also include used tires.
[0017] Waste plastics in the pyrolysis unit 10 are subjected to a
pyrolysis process to convert the waste plastics to one or more
pyrolysis oils which flow from the pyrolysis unit 10 via
hydrocarbon stream 12. The pyrolysis processes in the pyrolysis
unit 10 may be low severity or high severity. Low severity
pyrolysis processes may occur at a temperature of 250.degree. C. to
450.degree. C., may produce pyrolysis oils rich in mono- and
diolefins as well as a significant amount of aromatics, and may
include chloride compounds in amounts which cause the hydrocarbon
stream 12 to have the chloride compound concentrations disclosed
herein. High severity pyrolysis processes may occur at a
temperature of 450.degree. C. to 750.degree. C. and may produce
pyrolysis oils rich in aromatics. The liquid product of the high
severity processes may include chloride compounds which cause the
hydrocarbon stream 12 to have the chloride compound concentrations
disclosed herein.
[0018] In embodiments, the pyrolysis unit 10 may be one or more
vessels configured to convert waste plastics into gas phase and
liquid phase products (e.g., simultaneously). The one or more
vessels may contain one or more beds of inert material or pyrolysis
catalyst comprising sand, zeolite, or combinations thereof.
Generally, the pyrolysis catalyst is capable of transferring heat
to the components subject to the pyrolysis process in the pyrolysis
unit 10. In an embodiment where the pyrolysis unit 10 is two
vessels, the pyrolysis process may be divided into a first stage
which is performed in the first vessel and in a second stage
fluidly connected downstream of the first stage which is performed
in the second vessel. The first stage may utilize thermal cracking
of the waste plastics, and the second stage may utilize catalytic
cracking of the waste plastics to yield the hydrocarbon stream 12
flowing from the second stage. Alternatively, the first stage may
utilize catalytic cracking of the waste plastics, and the second
stage may utilize thermal cracking of the waste plastics to yield
the hydrocarbon stream 12 flowing from the second stage.
[0019] In additional or other embodiments, the pyrolysis unit 10
may include one or more equipment configured to convert waste
plastics into gas phase and liquid phase products. The one or more
equipment may or may not contain any inert material or pyrolysis
catalyst as described above. Examples of such equipment include one
or more of heated extruders, heated rotating kiln, heated tank-type
reactors, empty heated vessels, enclosed heated surfaces where
plastic flows down along the wall and cracks, vessels surrounded by
ovens or furnaces or other equipment offering a heated surface to
assist in cracking.
[0020] In one or more embodiments of the pyrolysis unit 10, a head
space purge gas is utilized in all or a portion of the pyrolysis
stage(s) (conversion of waste plastics to a liquid phase and/or gas
phase products) to enhance cracking of plastics, produce valuable
products, provide a feed for steam cracking, or combinations
thereof. The head space purge gas may include can utilize hydrogen
(H.sub.2), nitrogen (N.sub.2), steam, product gases, or
combinations thereof. The use of a head space purge gas assists in
the dechlorination in the pyrolysis unit 10. The use of hydrogen in
the pyrolysis unit 10 has beneficial effects of i) reducing the
coke lay down as a result of cracking, ii) keeps catalyst used (if
any) in the process in an active condition, iii) improves removal
of chloride from stream 1 such that the hydrocarbon stream 12 from
pyrolysis unit 10 is substantially dechlorinated with respect to
waste plastic stream 1 which minimizes the chloride removal
requirement in hydroprocessing reactor 20, iv) reduces diolefins in
hydrocarbon stream 12, v) helps operate the pyrolysis unit 10 at
reduced temperatures for same levels of conversion of waste plastic
stream 1 in the pyrolysis unit 10, or combinations of i)-v).
[0021] An example of a pyrolysis process for waste plastics is
disclosed in U.S. Pat. No. 8,895,790, which is incorporated by
reference in its entirety. Another example of a pyrolysis process
is disclosed in U.S. Provisional Patent Application No. 62/025,762,
titled "Upgrading Hydrogen Deficient Streams Using Hydrogen Donor
Streams in a Hydropyrolysis Process," filed Jul. 17, 2014, which is
incorporated by reference in its entirety.
[0022] The hydrocarbon stream 12 generally includes one or more
pyrolysis oils (e.g., plastic pyrolysis oil, tire pyrolysis oil).
In embodiments, the hydrocarbon stream 12 may include one or more
pyrolysis oils as described above which is blended with a heavier
oil (e.g., a naphtha or diesel, via spiking stream 14).
[0023] In an embodiment wherein the hydrocarbon stream 12 does not
contain the one or more sulphides in the concentrations disclosed
herein, the hydrocarbon stream 12 may be spiked with the one or
more sulphides, via a spiking stream 14 (discussed in more detail
below).
[0024] Examples of the components which may be included in the
hydrocarbon stream 12 include paraffins (n-paraffin, i-paraffin, or
both), olefins, naphthenes, aromatic hydrocarbons, or combinations
thereof. When the one or more hydrocarbons includes all the listed
hydrocarbons, the group of hydrocarbons may be collectively
referred to as a PONA feed (paraffin, olefin, naphthene, aromatics)
or PIONA feed (n-paraffin, paraffin, olefin, naphthene,
aromatics).
[0025] Any paraffin may be included in the hydrocarbon stream 12.
Examples of paraffins which may be included in the hydrocarbon
stream 12 include, but are not limited to, C.sub.1 to C.sub.22
n-paraffins and i-paraffins. In an embodiment, the concentration of
paraffins in the hydrocarbon stream 12 may be less than 10 wt %
based on the total weight of the hydrocarbon stream 12.
Alternatively, the concentration of paraffins in the hydrocarbon
stream 12 may be 10 wt %, 20 wt %, 30 wt %, 40 wt %, 50 wt %, 60 wt
%, or more based on the total weight of the hydrocarbon stream 12.
While embodiments include paraffins of carbon numbers up to 22, the
disclosure is not limited to carbon number 22 as an upper end-point
of the suitable range of paraffins, and the paraffins can include
higher carbon numbers, e.g., 22, 23, 24, 25, 26, 27, 28, 29, 30,
31, 32, 33, 34, 35, 36, 37, 38, 39, 40, and higher. In embodiments,
at least a portion of the paraffins in the hydrocarbon stream 12
comprises at least a portion of the heavy hydrocarbon
molecules.
[0026] Any olefin may be included in the hydrocarbon stream 12.
Examples of olefins which may be included in hydrocarbon stream 12
include, but are not limited to, C.sub.2 to C.sub.10 olefins and
combinations thereof. In an embodiment, the concentration of
olefins in the hydrocarbon stream 12 may be less than 10 wt % based
on the total weight of the hydrocarbon stream 12. Alternatively,
the concentration of olefins in the hydrocarbon stream 12 may be 10
wt %, 20 wt %, 30 wt %, 40 wt % or more based on the total weight
of the hydrocarbon stream 12. In embodiments, at least a portion of
the one or more olefins in the hydrocarbon stream 12 comprise at
least a portion of the heavy hydrocarbon molecules. Alternatively,
none of the heavy hydrocarbon molecules in the hydrocarbon stream
12 are olefins. While embodiments include olefins of carbon numbers
up to 10, the disclosure is not limited to carbon number 10 as an
upper end-point of the suitable range of olefins, and the olefins
can include higher carbon numbers, e.g., 11, 12, 13, 14, 15, 16,
17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, and
higher.
[0027] In an embodiment, the hydrocarbon stream 12 comprises no
olefins.
[0028] Any naphthene may be included in the hydrocarbon stream 12.
Examples of naphthenes include, but are not limited to,
cyclopentane, cyclohexane, cycloheptane, and cyclooctane. In an
embodiment, the concentration of naphthenes in the hydrocarbon
stream 12 may be less than 10 wt % based on the total weight of the
hydrocarbon stream 12. Alternatively, the concentration of
naphthenes in the hydrocarbon stream 12 may be 10 wt %, 20 wt %, 30
wt %, 40 wt % or more based on the total weight of the hydrocarbon
stream 12. While embodiments include naphthenes of carbon numbers
up to 8, the disclosure is not limited to carbon number 8 as an
upper end-point of the suitable range of naphthenes, and the
naphthenes can include higher carbon numbers, e.g., 9, 10, 11, 12,
13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29,
30, and higher. In embodiments, at least a portion of the
naphthenes in the hydrocarbon stream 12 comprise at least a portion
of the heavy hydrocarbon molecules.
[0029] Any aromatic hydrocarbon may be included in the hydrocarbon
stream 12. Aromatic hydrocarbons suitable for use in the
hydrocarbon stream 12 include, but are not limited to, benzene,
toluene, xylenes, ethyl benzene, or combinations thereof. In an
embodiment, the concentration of aromatic hydrocarbons in the
hydrocarbon stream 12 may be less than 10 wt % based on the total
weight of the hydrocarbon stream 12. Alternatively, the
concentration of aromatic hydrocarbons in the hydrocarbon stream 12
may be 10 wt %, 20 wt %, 30 wt %, 40 wt % or more based on the
total weight of the hydrocarbon stream 12. While embodiments
include aromatic hydrocarbons of carbon numbers up to 8, the
disclosure is not limited to carbon number 8 as an upper end-point
of the suitable range of aromatic hydrocarbons, and the aromatic
hydrocarbons can include higher carbon numbers, e.g., 9, 10, 11,
12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28,
29, 30, and higher. In an embodiment, the aromatic hydrocarbons
carbon number is as high as 22. In embodiments, at least a portion
of the aromatics in the hydrocarbon stream 12 comprise at least a
portion of the heavy hydrocarbon molecules.
[0030] In an embodiment, the hydrocarbon stream 12 comprises no
aromatic hydrocarbons.
[0031] As discussed herein, embodiments of the processes disclosed
herein contemplate hydrocracking of molecules, and in particular,
heavy hydrocarbon molecules of the hydrocarbon stream 12. As such,
it is contemplated that at least a portion of the pyrolysis oils
comprises heavy hydrocarbon molecules (e.g., also referred to as
heavy ends of the pyrolysis oils). Hydrocracking of the heavy ends
of the pyrolysis oils to meet steam cracker 50 specifications is
contemplated. In an embodiment, the concentration of heavy
hydrocarbon molecules in the hydrocarbon stream 12 may be less than
10 wt % based on the total weight of the hydrocarbon stream 12.
Alternatively, the concentration of the heavy hydrocarbon molecules
in the hydrocarbon stream 12 may be 10 wt % to 90 wt % based on the
total weight of the hydrocarbon stream 12. As described above, the
heavy hydrocarbon molecules may include paraffins, i-paraffins,
olefins, naphthenes, aromatic hydrocarbons, or combinations
thereof. In embodiments, the heavy hydrocarbon molecules may
include C.sub.16 and larger hydrocarbons. Greater than 5, 10, 15,
20, 25, 30 wt % or more of the heavy hydrocarbon molecules in the
hydrocarbon stream 12 is hydrocracked when the hydrocarbon stream
12 is contacted with the hydroprocessing catalyst in the
hydroprocessing reactor 20. In an embodiment, the hydrocarbon
stream 12 may have 2 wt % or less in a liquid phase which boils
above 370.degree. C.
[0032] Chloride compounds which may be included in the hydrocarbon
stream 12 include, but are not limited to, aliphatic
chlorine-containing hydrocarbons, aromatic chlorine-containing
hydrocarbons, and other chlorine-containing hydrocarbons. Examples
of chlorine-containing hydrocarbons include, but are not limited
to, 1-chlorohexane (C.sub.6H.sub.13Cl), 2-chloropentane
(C.sub.5H.sub.11Cl), 3-chloro-3-methyl pentane (C.sub.6H.sub.13Cl),
(2-chloroethyl) benzene (C.sub.8H.sub.9Cl), chlorobenzene
(C.sub.6H.sub.5Cl), or combinations thereof. The concentration of
chloride compounds in the hydrocarbon stream 12 may be 5 ppm, 6
ppm, 7 ppm, 8 ppm, 9 ppm, 10 ppm, 15 ppm, 20 ppm, 30 ppm, 40 ppm,
50 ppm, 100 ppm, 200 ppm, 300 ppm, 400 ppm, 500 ppm, 600 ppm, 700
ppm, 800 ppm, 900 ppm, 1,000 ppm, 1,100 ppm, 1,200 ppm, 1,300 ppm,
1,400 ppm, 1,500 ppm, 1,600 ppm, 1,700 ppm, 1,800 ppm, 1,900 ppm,
2,000 ppm or more based on the total weight of the hydrocarbon
stream 12.
[0033] Sulphides which may be included in the hydrocarbon stream 12
include sulphur-containing compounds. For example, a sulphiding
agent such as dimethyl disulphide (C.sub.2H.sub.6S.sub.2), dimethyl
sulphide (C.sub.2H.sub.6S), mercaptans (R--SH), carbon disulphide
(CS.sub.2), hydrogen sulphide (H.sub.2S), or combinations thereof
may be used as the sulphide in the hydrocarbon stream 12.
[0034] In an embodiment, one or more sulphides (e.g., dimethyl
disulphide (C.sub.2H.sub.6S.sub.2), dimethyl sulphide
(C.sub.2H.sub.6S), mercaptans (R--SH), carbon disulphide
(CS.sub.2), hydrogen sulphide (H.sub.2S), or combinations thereof)
are added to the hydrocarbon stream 12 (e.g., the hydrocarbon
stream 12 is "spiked" with one or more sulphides), for example, via
a spiking stream 14, before the hydrocarbon stream 12 is introduced
to the hydroprocessing reactor 20. In such embodiments, the one or
more sulphides are added to the hydrocarbon stream 12 in an amount
such that a sulphur content of the hydrocarbon stream 12, after
sulphide addition, is about 0.5 wt %, 1 wt %, 1.5 wt %, 2 wt %, 2.5
wt %, 3 wt %, 3.5 wt %, 4 wt %, 4.5 wt %, 5 wt % or more based on
the total weight of the hydrocarbon stream 12. In embodiments, the
spiking stream 14 may include components tailored for spiking such
as hexadecane and dimethyl disulphide; alternatively, the spiking
stream 14 may be a heavier oil (e.g., naphtha, diesel, or both)
which already contains sulphide compounds (or to which sulphides
are spiked to achieve the sulphur content disclosed herein) and
which is blended with the hydrocarbon stream 12 to achieve the
sulphur content described above.
[0035] In alternative embodiments, one or more sulphides are
present in the hydrocarbon stream as a result of upstream
processing from which the hydrocarbon stream 12 flows. In such
embodiments, the hydrocarbon stream 12 may contain one or more
sulphides in an amount such that a sulphur content of the
hydrocarbon stream 12, without sulphide spiking, is about 0.5 wt %,
1 wt %, 1.5 wt %, 2 wt %, 2.5 wt %, 3 wt %, 3.5 wt %, 4 wt %, 4.5
wt %, 5 wt % or more based on the total weight of the hydrocarbon
stream 12.
[0036] In yet other embodiments, the hydrocarbon stream 12 may
contain one or more sulphides in an amount insufficient for
sulphiding (e.g., less than 5,000, 4,000, 3,000, 2,000, 1,000, 900,
800, 700, 600, 500, 400, 300, 200, 100, 90, 80, 70, 60, 50, 40, 30,
20, 10, 5, or 1 ppm) the hydroprocessing catalyst contained in the
hydroprocessing reactor 20 (the catalyst is discussed in more
detail below), and spiking stream 14 is utilized to raise the
concentration of the one or more sulphides in the hydrocarbon
stream to such that a sulphur content of the hydrocarbon stream 12,
after sulphide addition, is about 0.5 wt %, 1 wt %, 1.5 wt %, 2 wt
%, 2.5 wt %, 3 wt %, 3.5 wt %, 4 wt %, 4.5 wt %, 5 wt % or more
based on the total weight of the hydrocarbon stream 12.
[0037] In an embodiment, the sulphur content of the hydrocarbon
stream 12, after sulphide addition using spiking stream 14, is up
to about 3 wt % based on the total weight of the hydrocarbon stream
12. In another embodiment, the sulphur content of the hydrocarbon
stream 12, without sulphide addition using spiking stream 14, is up
to about 3 wt % based on the total weight of the hydrocarbon stream
12.
[0038] The hydroprocessing reactor 20 is configured to
dechlorinate, hydrogenate, and hydrocrack components of the
hydrocarbon stream 12 fed to the hydroprocessing reactor 20. In the
hydroprocessing reactor 20, the hydrocarbon stream 12 is contacted
with the hydroprocessing catalyst in the presence of hydrogen to
yield a hydrocarbon product in stream 22. It is contemplated the
hydrocarbon stream 12 may be contacted with the hydroprocessing
catalyst in upward flow, downward flow, radial flow, or
combinations thereof, with or without a staged addition of
hydrocarbon stream 12, spiking stream 14, a H.sub.2 stream 24, or
combinations thereof. It is further contemplated the components of
the hydrocarbon stream 12 may be in the liquid phase, a
liquid-vapor phase, or a vapor phase while in the hydroprocessing
reactor 20.
[0039] The hydroprocessing reactor 20 may facilitate any reaction
of the components of the hydrocarbon stream 12 in the presence of,
or with, hydrogen. Reactions may occur as the addition of hydrogen
atoms to double bonds of unsaturated molecules (e.g., olefins,
aromatic compounds), resulting in saturated molecules (e.g.,
paraffins, i-paraffins, naphthenes). Additionally, reactions in the
hydroprocessing reactor 20 may cause a rupture of a bond of an
organic compound, resulting in "cracking" of a hydrocarbon molecule
into two or more smaller hydrocarbon molecules, or resulting in a
subsequent reaction and/or replacement of a heteroatom with
hydrogen. Examples of reactions which may occur in the
hydroprocessing reactor 20 include, but are not limited to, the
hydrogenation of olefins, removal of heteroatoms from
heteroatom-containing hydrocarbons (e.g., dechlorination),
hydrocracking of large paraffins or i-paraffins to smaller
hydrocarbon molecules, hydrocracking of aromatic hydrocarbons to
smaller cyclic or acyclic hydrocarbons, conversion of one or more
aromatic compounds to one or more cycloparaffins, isomerization of
one or more normal paraffins to one or more i-paraffins, selective
ring opening of one or more cycloparaffins to one or more
i-paraffins, or combinations thereof.
[0040] In an embodiment, contacting the hydrocarbon stream 12 with
the hydroprocessing catalyst in the presence of hydrogen yields a
hydrocarbon product comprising C.sub.1 to C.sub.4 gases and
C.sub.5+ (C.sub.5 and heavier) liquid hydrocarbons. As explained
below, the separator 30 recovers the C.sub.5+ liquid hydrocarbons
in the treated hydrocarbon stream 32. The C.sub.1 to C.sub.4 gases
can be recovered in hydroprocessed light gas stream 36.
[0041] In embodiments, the hydroprocessing reactor 20 may be any
vessel configured to contain the hydroprocessing catalyst disclosed
herein. The vessel may be configured for gas phase, liquid phase,
vapor-liquid phase, or slurry phase operation. The hydroprocessing
reactor 20 may include one or more beds of the hydroprocessing
catalyst in fixed bed, fluidized bed, moving bed, ebullated bed,
slurry bed, or combinations thereof, configuration. The
hydroprocessing reactor 20 may be operated adiabatically,
isothermally, nonadiabatically, non-isothermally, or combinations
thereof.
[0042] The reactions of this disclosure may be carried out in a
single stage or in multiple stages. For example, the
hydroprocessing reactor 20 can be two reactor vessels fluidly
connected in series, each having one or more catalyst beds of the
hydrogenating catalyst. Alternatively, two or more stages for
hydroprocessing may be contained in a single reactor vessel. In
embodiments having multiple stages, the first stage may
dechlorinate and hydrogenate components of the hydrocarbon stream
12 to yield a first hydrocarbon product having a first level of
chloride compounds and olefins. The first hydrocarbon product may
flow from the first stage to the second stage, where other
components of the first hydrocarbon product are dechlorinated and
hydrogenated to yield a second hydrocarbon product stream (stream
22 in FIG. 1) having a second level of chloride compounds and
olefins. In either one or multiple reactors, the sulphur present in
the feed is also removed as H.sub.2S to provide a reduced level of
sulphur (e.g., sulphur content less than 200, 100, 90, 80, 70, 60,
50, 40, 30, 20, 10, 9, 8, 7, 6, 5, 4, 3, 2, 1, 0.5, 0.1 ppmw S
based on total weight of stream 22) acceptable for downstream
processing in steam cracker 50 and refinery units. The second
hydrocarbon stream may then be treated as described herein for
stream 22.
[0043] Embodiments of the disclosure contemplate a second
hydroprocessing reactor and a second hydroprocessing separator may
be placed in between separator 30 and treated hydrocarbon stream
32. The treated product flowing from the separator 30, in such
embodiments, may contain residual sulphur, and the second
hydroprocessing reactor/second separator combination may treat the
treated product flowing from the separator 30 to completely remove
the sulphur such that a second treated product flowing in the
treated hydrocarbon stream 32 from the second separator contains
less than 200, 100, 90, 80, 70, 60, 50, 40, 30, 20, 10, 9, 8, 7, 6,
5, 4, 3, 2, 1, 0.5, 0.1 ppmw S based on total weight of the treated
hydrocarbon stream 32. In embodiments having a second
hydroprocessing reactor, C.sub.1 to C.sub.4 hydrocarbon gases
generated in the second hydroprocessing reactor may flow from the
second hydroprocessing reactor in a second hydroprocessed light gas
stream. Similar to the hydroprocessed light gas stream 36 flowing
from the separator 30, the second hydroprocessed light gas stream
may flow directly to the steam cracker 50, may flow to a light gas
scrubbing unit 60 and then to the steam cracker 50, or may be
blended with another light gas (treated or not) stream before
flowing to the steam cracker 50.
[0044] In an embodiment, the hydroprocessing reactor 20 may
comprise one or more vessels.
[0045] In embodiments of a single vessel or multiple vessels, the
sulphur present in the hydrocarbon stream 12 is removed as H.sub.2S
to provide a reduced level of sulphur acceptable for downstream
processing in steam crackers and refinery units.
[0046] In an embodiment, hydrogen may feed to the hydroprocessing
reactor 20 in stream 24. The rate of hydrogen addition to the
hydroprocessing reactor 20 is generally sufficient to achieve the
hydrogen-to-hydrocarbon ratios disclosed herein.
[0047] The disclosed hydroprocessing reactor 20 may operate at
various process conditions. For example, contacting the hydrocarbon
stream 12 with the hydroprocessing catalyst in the presence of
hydrogen may occur in the hydroprocessing reactor 20 at a
temperature of 100.degree. C. to 450.degree. C.; alternatively,
100.degree. C. to 350.degree. C.; or alternatively, 260.degree. C.
to 350.degree. C. Contacting the hydrocarbon stream 12 with the
hydroprocessing catalyst in the presence of hydrogen may occur in
the hydroprocessing reactor 20 at a pressure of 1 barg to 200 barg;
or alternatively, 20 barg to 60 barg. Contacting the hydrocarbon
stream 12 with the hydroprocessing catalyst in the presence of
hydrogen may occur in the hydroprocessing reactor 20 at a weight
hourly space velocity (WHSV) of between 0.1 hr.sup.-1 to 10
hr.sup.-1; or alternatively, 1 hr.sup.-1 to 3 hr.sup.-1. Contacting
the hydrocarbon stream 12 with the hydroprocessing catalyst in the
presence of hydrogen may occur in the hydroprocessing reactor 20 at
a hydrogen-to-hydrocarbon (H.sub.2/HC) flow ratio of 10 to 3,000
NL/L; or alternatively, 200 to 800 NL/L.
[0048] It is contemplated that dechlorination using the
hydroprocessing catalyst as described herein is performed in the
hydroprocessing reactor 20 without the use of chlorine sorbents,
without addition of Na.sub.2CO.sub.3 in an effective amount to
function as a dechlorinating agent, or both.
[0049] The hydroprocessing catalyst may be any catalyst used for
hydrogenation (e.g., saturation) of olefins and aromatic
hydrocarbons (e.g., a commercially available hydrotreating
catalyst). In an embodiment, the hydroprocessing catalyst is a
cobalt and molybdenum catalyst (Co--Mo catalyst) on an alumina
support. In other embodiments, the hydroprocessing catalyst is a
nickel and molybdenum catalyst (Ni--Mo catalyst) on an alumina
support or tungsten and molybdenum catalyst (W--Mo catalyst) on an
alumina support. Other catalyst embodiments may include platinum
and palladium catalyst (Pt--Pd catalyst) on an alumina support,
nickel sulphides suitable for slurry processing, molybdenum
sulphides suitable for slurry processing, nickel and molybdenum
sulphides, or combinations thereof. In embodiments where the
hydrocarbon stream 12 comprises one or more sulphides and one or
more chloride compounds, contacting the hydrocarbon carbon stream
12 with the hydroprocessing catalyst acts to activate the
hydroprocessing catalyst by sulphiding and to acidify the
hydroprocessing catalyst by chlorinating. Continuously contacting
the hydroprocessing catalyst with the hydrocarbon stream 12
containing the one or more sulphides, the one or more chloride
compounds, or both, may maintain the catalyst activity on a
continuous basis.
[0050] In embodiments, the hydroprocessing catalyst is activated
and/or the activity is maintained by sulphiding the hydroprocessing
catalyst in-situ. For example, the hydroprocessing catalyst may be
sulphided (i.e., activated) and/or sulphiding (i.e., maintaining
the catalyst activity) of the hydroprocessing catalyst may be
performed (e.g., maintaining the hydroprocessing catalyst in
sulphided form is accomplished) by continuously contacting the
hydrocarbon stream 12 containing one or more sulphides with the
hydroprocessing catalyst. The one or more sulphides may be included
in the hydrocarbon stream 12 in an amount such that the sulphur
content of the hydrocarbon stream 12 is about 0.5 wt %, 1 wt %, 1.5
wt %, 2 wt %, 2.5 wt %, 3 wt %, 3.5 wt %, 4 wt %, 4.5 wt %, or 5 wt
% based on the total weight of the hydrocarbon stream 12.
[0051] Alternatively, the hydroprocessing catalyst may be sulphided
(i.e., activated) by contacting a catalyst activating stream 26
containing one or more sulphides with the hydroprocessing catalyst
for a period of time (e.g., 1, 2, 3, 4, 5, 6, 7, 8, 9 or more
hours) sufficient to activate the hydroprocessing catalyst (before
contacting the hydrocarbon stream 12 with the hydroprocessing
catalyst). In such embodiments, the catalyst activating stream 26
may include a hydrocarbon carrier for the one or more sulphides,
such as hexadecane. The one or more sulphides may be included in
the catalyst activating stream 26 in an amount such that the
sulphur content of the catalyst activating stream 26 is about 0.5
wt %, 1 wt %, 1.5 wt %, 2 wt %, 2.5 wt %, 3 wt %, 3.5 wt %, 4 wt %,
4.5 wt %, 5 wt % or more based on the total weight of the catalyst
activating stream 26. After the hydroprocessing catalyst is
activated with the catalyst activating stream 26, flow of the
catalyst activating stream 26 may be discontinued, and sulphiding
(i.e., maintaining the catalyst activity) of the hydroprocessing
catalyst may be maintained (e.g., maintaining the hydroprocessing
catalyst in sulphided form is accomplished) by continuously
contacting the hydrocarbon stream 12 containing one or more
sulphides with the hydroprocessing catalyst. The one or more
sulphides may be included in the hydrocarbon stream 12 in an amount
such that the sulphur content of the hydrocarbon stream 12 is about
0.5 wt %, 1 wt %, 1.5 wt %, 2 wt %, 2.5 wt %, 3 wt %, 3.5 wt %, 4
wt %, 4.5 wt %, or 5 wt % based on the total weight of the
hydrocarbon stream 12.
[0052] In embodiments, sulphiding and maintaining the catalyst in
sulphided form may use two different concentrations of sulphur
content in the hydrocarbon stream 12. For example, the one or more
sulphides may be included (e.g., provided via spiking stream 14) in
the hydrocarbon stream 12 in an amount such that the sulphur
content of the hydrocarbon stream 12 is about 2 wt % based on the
total weight of the hydrocarbon stream 12 for sulphiding, and the
one or more sulphides may be maintained (e.g., via spiking stream
14) in the hydrocarbon stream 12 in an amount such that the sulphur
content of the hydrocarbon stream 12 is about 2 wt % based on the
total weight of the hydrocarbon stream 12 for maintaining the
hydroprocessing catalyst in the sulphided form. In another example,
the one or more sulphides may be included in the catalyst
activating stream 26 in an amount such that the sulphur content of
the catalyst activating stream 26 is about 3 wt % based on the
total weight of the catalyst activating stream 26 for sulphiding,
and the one or more sulphides may be included (e.g., via spiking
stream 14) in the hydrocarbon stream 12 in an amount such that the
sulphur content of the hydrocarbon stream 12 is about 2 wt % based
on the total weight of the hydrocarbon stream 12 for maintaining
the hydroprocessing catalyst in the sulphided form.
[0053] In embodiments, catalyst activity is also maintained by
chloriding the hydroprocessing catalyst. The hydroprocessing
catalyst is chlorided using the one more chloride compounds
provided to the hydroprocessing catalyst by the hydrocarbon stream
12. The one or more chloride compounds which contribute to
acidification of the hydroprocessing catalyst may be included in
the hydrocarbon stream 12 in concentrations disclosed herein.
[0054] Sulphiding and maintaining the hydroprocessing catalyst in
sulphided form result in a hydroprocessing catalyst which has
hydrogenation sites (sulphided metal) for hydrogenation of
components of the hydrocarbon stream 12. Chloriding the
hydroprocessing catalyst results in a hydroprocessing catalyst
which has hydrocracking sites (chloride alumina) for hydrocracking
components of the hydrocarbon stream 12.
[0055] Due to hydrogenation reactions in the hydroprocessing
reactor 20, in embodiments, the hydrocarbon product stream 22 may
contain one or more olefins in a concentration of less than 1 wt %
based on the total weight of the hydrocarbon product stream 22. It
is also contemplated that the concentration of aromatic
hydrocarbons in the hydrocarbon product stream 22 is less than the
concentration of aromatic hydrocarbons in the hydrocarbon stream 12
due to hydrogenation of at least a portion of the aromatic
hydrocarbons in the hydroprocessing reactor 20. For example,
aromatic hydrocarbons may be present in the hydrocarbon product
stream 22 in a concentration of less than 10, 9, 8, 7, 6, 5, 4, 3,
2, or 1 wt % based on the total weight of the hydrocarbon product
stream 22. In an embodiment, the hydrocarbon product stream 22 may
have 2 wt % or less in a liquid phase which boils above 370.degree.
C.
[0056] The reaction product flows as effluent from the
hydroprocessing reactor 20 in the hydrocarbon product stream 22 to
the separator 30. Separator 30 may be any vessel which can recover
a treated hydrocarbon stream 32 from the hydrocarbon product 22
which is fed to the separator 30. In embodiments, the treated
hydrocarbon stream 32 may be recovered by separating a treated
product (e.g., liquid product or gas product) from sulphur and
chlorine-containing gas in the separator 30, and flowing the
treated product in the treated hydrocarbon stream 32 from the
separator 30.
[0057] In an embodiment, the separator 30 is a condenser which
operates at conditions which condense a portion of the hydrocarbon
product stream 22 into the treated product (e.g., liquid product or
treated liquid product) while leaving sulphur and
chlorine-containing compounds in the gas phase. The treated liquid
product flows from the separator 30 in treated hydrocarbon stream
32, and the sulphur and chlorine-containing gas flows from the
separator 30 via hydroprocessed light gas stream 36. In such
embodiments, the treated liquid product may comprise C.sub.5+
(C.sub.5 and heavier) liquid hydrocarbons.
[0058] In another embodiment, the separator 30 is a scrubbing unit
containing a caustic solution (e.g., a solution of sodium hydroxide
in water) which removes (e.g., via reaction, adsorption,
absorption, or combinations thereof) sulphur and
chlorine-containing gases from the hydrocarbon product stream 22 to
yield the treated product which flows from the separator 30 via
treated hydrocarbon stream 32 while the C.sub.1 to C.sub.4
hydrocarbons and sulphur and chlorine-containing compounds are
removed from the separator 30 via hydroprocessed light gas stream
36. In such embodiments, the treated liquid product may comprise
C.sub.5+ (C.sub.5 and heavier) liquid hydrocarbons.
[0059] In yet another embodiment, the separator 30 is a condenser
in communication with one or more stages of a gas-liquid separator
positioned downstream of the condenser and a scrubbing unit
containing a caustic solution. As described above, the condenser
may operate at conditions which condense a portion of the
hydrocarbon product stream 22 into a mid-treated product (e.g.,
liquid product or treated liquid product) while leaving sulphur and
chlorine-containing compounds in the gas phase. In such
embodiments, the mid-treated product may comprise C.sub.5+ (C.sub.5
and heavier) liquid hydrocarbons. The mid-treated liquid product
and the mid-treated gas product flow from the first stage of the
gas-liquid separator, and the mid-treated gas product is treated in
the scrubbing unit of the separator 30. The mid-treated liquid
product flows out of the first stage of the gas-liquid separator
and experiences a pressure reduction (e.g., via a valve or other
pressure reducing device known in the art with the aid of this
disclosure), which creates an effluent gas (e.g., via flashing)
which flows to the scrubbing unit for further removal of sulphur
and chlorine-containing compounds from the liquid hydrocarbons. The
treated product flowing in hydrocarbon stream 32 flows from the
scrubbing unit of the separator 30 to the polishing zone 40 via
stream 32. Sulphur and chlorine-containing compounds flow from the
separator 30 in hydroprocessed light gas stream 36.
[0060] In embodiments disclosed herein, no hydrogen halides and no
halogenated organic compounds are recycled to the hydroprocessing
reactor 20.
[0061] In embodiments, the treated hydrocarbon stream 32 includes
one or more chloride compounds in a concentration of less than 5
ppm, 4 ppm, 3 ppm, 2 ppm, 1 ppm, or 0.5 ppm based on a total weight
of the treated hydrocarbon stream 32. It is contemplated that the
one or more chloride compounds in the treated hydrocarbon stream 32
may be the same as some or all of the one or more chloride
compounds in the hydrocarbon stream 12; alternatively, it is
contemplated that only some of the one or more chloride compounds
in the treated hydrocarbon stream 32 are the same as only some of
the one or more chloride compounds in the hydrocarbon stream 12;
alternatively, it is contemplated that none of the one or more
chloride compounds in the treated hydrocarbon stream 32 are the
same as the one or more chloride compounds in the hydrocarbon
stream 12.
[0062] In additional embodiments, the treated hydrocarbon stream 32
includes the one or more olefins in a concentration which is less
than a concentration of the one or more olefins in the hydrocarbon
stream 12 due to hydrogenation of at least a portion of the one or
more olefins from the hydrocarbon stream 12 while the hydrocarbon
stream 12 is contacted with the hydroprocessing catalyst in the
hydroprocessing reactor 20. In yet additional embodiments, the
treated hydrocarbon stream 32 includes the one or more olefins in a
concentration which is less than a concentration of the one or more
olefins in the hydrocarbon stream 12 due to hydrogenation and
hydrocracking of at least a portion of the one or more olefins from
the hydrocarbon stream 12 while the hydrocarbon stream 12 is
contacted with the hydroprocessing catalyst in the hydroprocessing
reactor 20. In an embodiment, the one or more olefins are present
in the treated hydrocarbon stream 32 in a concentration of less
than 1 wt % based on the total weight of the treated hydrocarbon
stream 32.
[0063] In embodiments, the treated hydrocarbon stream 32 includes
one or more paraffins, and one or more olefins in a concentration
of less than 1 wt % based on the total weight of the treated
hydrocarbon stream 32. It is also contemplated that the
concentration of aromatic hydrocarbons in the treated hydrocarbon
stream 32 is less than the concentration of aromatic hydrocarbons
in the hydrocarbon stream 12 due to hydrogenation of at least a
portion of the aromatic hydrocarbons in the hydroprocessing reactor
20. For example, aromatic hydrocarbons may be present in the
treated hydrocarbon stream 32 in a concentration of less than 10,
9, 8, 7, 6, 5, 4, 3, 2, or 1 wt % based on the total weight of the
treated hydrocarbon product stream 32.
[0064] In embodiments, the treated hydrocarbon stream 32 may have a
reduced concentration of heavy hydrocarbon molecules compared to
the concentration of heavy hydrocarbon molecules in the hydrocarbon
stream 12 due to hydrocracking of at least a portion of the heavy
hydrocarbon molecules from the hydrocarbon stream 12 while the
hydrocarbon stream 12 is contacted with the hydroprocessing
catalyst. In further embodiments, the treated hydrocarbon stream 32
may comprise none of the heavy hydrocarbon molecules form the
hydrocarbon stream 12 due to hydrocracking of the heavy hydrocarbon
molecules in the hydroprocessing reactor 20. Due to hydrocracking
of heavy hydrocarbon molecules when the hydrocarbon stream 12 is
contacted with the hydroprocessing catalyst in the hydroprocessing
reactor 20, the treated hydrocarbon stream 32 may have a boiling
end point of 370.degree. C. In an embodiment, the treated
hydrocarbon stream 32 may have 2 wt % or less in a liquid phase
which boils above 370.degree. C.
[0065] In embodiments where the treated hydrocarbon stream 32
includes one or more chloride compounds in a concentration of less
than 3 ppm, the treated hydrocarbon product flowing in treated
hydrocarbon stream 32 may be fed directly to the steam cracker 50
by flowing through bypass stream 34. In alternative embodiments
where the treated hydrocarbon stream 32 includes one or more
chloride compounds in a concentration of 3 ppm or more (e.g., 3 ppm
to 5 ppm), the treated hydrocarbon stream 32 may flow to the
polishing zone 40 in order to reduce the chloride content to meet
the requirements of the steam cracker 50.
[0066] To further reduce chloride content, embodiments of the
processes disclosed herein may include dechlorinating the treated
hydrocarbon stream 32 to yield a polished hydrocarbon stream 42.
Dechlorination may occur in the polishing zone 40. The polishing
zone 40 may be considered a polishing stage in which the treated
hydrocarbon stream 32 is "polished" to reduce the chloride content.
In order to use the hydroprocessing catalyst in the hydroprocessing
reactor 20 until end-of-run conditions (e.g., in order to maintain
hydrogenation/saturation performance), the operating temperature
(e.g., the catalyst bed temperature) of the hydroprocessing reactor
20 may be increased. As the operating temperature of the
hydroprocessing reactor 20 is increased, operating conditions may
not yield a chloride content in the treated hydrocarbon stream 32
which meets the requirements for the steam cracker 50 (e.g., at
temperatures above 350.degree. C. the treated hydrocarbon stream 32
may have a chloride content 3-5 ppm and not less than 3 ppm as
required by the steam cracker 50). In such embodiments, the treated
hydrocarbon stream 32 may be diverted from flowing in the bypass
stream 34 and may be directed to flow to the polishing zone 40 for
further chloride removal such that a polished hydrocarbon stream 42
flowing from the polishing zone 40 has a concentration of one or
more chlorides which meet the requirement of the steam cracker
50.
[0067] Similar to the hydroprocessed light gas stream 36 flowing
from the separator 30, a polished light gas stream 46 comprising
C.sub.1 to C.sub.4 gases generated in the polishing zone 40 (e.g.,
in hydroprocessing reactor 41 of FIG. 2) may flow directly to the
steam cracker 50, may flow to the light gas scrubbing unit 60 and
then to the steam cracker 50, or may be blended with another light
gas (treated or not) stream before flowing to the steam cracker
50.
[0068] In an embodiment, dechlorinating the treated hydrocarbon
stream 32 may include removing at least a portion of the one or
more chloride compounds remaining in the treated hydrocarbon stream
32 via adsorptive dechlorination to yield the polished hydrocarbon
stream 42. Removal of remaining chloride compounds may occur in the
polishing zone 40 in the form of one or more adsorption units. The
one or more adsorption units may contain one or more adsorbents
(e.g., goethite, hematite, magnetite, alumina, alumino-silicate,
gamma alumina, or combinations thereof) which removes (e.g., via
reaction, adsorption, absorption, or combinations thereof) a
portion of the one or more remaining chloride compounds from the
treated hydrocarbon stream 32 to yield a polished hydrocarbon
product which flows from the adsorption unit via polished
hydrocarbon stream 42. One or more chloride compounds which are
removed by the sorbent in the adsorption unit may be recovered from
the adsorption unit(s) via processes known in the art with the aid
of this disclosure (e.g., regeneration of adsorption units
operating in parallel). An example of an adsorption process
suitable for use in the polishing zone 40 is found in U.S. Patent
Publication No. 2015/053,589, which is hereby incorporated by
reference.
[0069] In an additional or alternative embodiment, dechlorinating
the treated hydrocarbon stream 32 may include contacting the
treated hydrocarbon stream 32 with a second hydroprocessing
catalyst in the presence of hydrogen to yield a second hydrocarbon
product. In such embodiments, the polishing zone 40 may be a second
hydroprocessing stage in the system 100. That is, in embodiments,
the polishing zone 40 may include another hydroprocessing reactor
which is the second stage of hydroprocessing in a two-stage
hydroprocessing configuration (the hydroprocessing reactor 20 being
the first stage). FIG. 2 illustrates a polishing zone 40 which is a
second stage of hydroprocessing.
[0070] Referring to FIG. 2, the hydroprocessing reactor 41 of the
polishing zone 40 is configured to dechlorinate, hydrogenate, and
hydrocrack components of the treated hydrocarbon stream 32 fed to
the hydroprocessing reactor 41. In the hydroprocessing reactor 41,
the treated hydrocarbon stream 32 is contacted with a second
hydroprocessing catalyst in the presence of hydrogen to yield a
second hydrocarbon product in stream 43. It is contemplated the
treated hydrocarbon stream 32 may be contacted with the
hydroprocessing catalyst in upward flow, downward flow, radial
flow, or combinations thereof. It is further contemplated the
components of the treated hydrocarbon stream 32 may be in the
liquid phase, a liquid-vapor phase, or a vapor phase while in the
hydroprocessing reactor 41.
[0071] The hydroprocessing reactor 41 may facilitate dechlorination
of the treated hydrocarbon stream 32 in the presence of, or with,
hydrogen. Other reactions in addition to dechlorination reactions
may occur in hydroprocessing reactor 41, for example, the reactions
discussed for hydroprocessing reactor 20.
[0072] In embodiments, the hydroprocessing reactor 41 may be any
vessel configured to contain the hydroprocessing catalyst disclosed
herein. The vessel may be configured for gas phase, liquid phase,
vapor-liquid phase, or slurry phase operation. The hydroprocessing
reactor 41 may include one or more beds of the second
hydroprocessing catalyst in fixed bed, fluidized bed, moving bed,
ebullated bed, slurry bed, or combinations thereof, configuration.
The hydroprocessing reactor 41 may be operated adiabatically,
isothermally, nonadiabatically, non-isothermally, or combinations
thereof.
[0073] In an embodiment, hydrogen may feed to the hydroprocessing
reactor 41 in stream 44. The rate of hydrogen addition to the
hydroprocessing reactor 41 is generally sufficient to achieve the
hydrogen-to-hydrocarbon ratios disclosed herein.
[0074] The hydroprocessing reactor 41 may operate within the same
ranges for temperature, pressure, weight hourly space velocity
(WHSV), and hydrogen-to-hydrocarbon (H.sub.2/HC) flow ratio
disclosed for hydroprocessing reactor 20. In embodiments, while the
hydroprocessing reactor 20 and hydroprocessing reactor 41 may
operate within the same ranges, the values for temperature,
pressure, weight hourly space velocity (WHSV), and
hydrogen-to-hydrocarbon (H.sub.2/HC) flow ratio of the
hydroprocessing reactor 41 may or may not be the same as the values
for temperature, pressure, weight hourly space velocity (WHSV), and
hydrogen-to-hydrocarbon (H.sub.2/HC) flow ratio of the
hydroprocessing reactor 20. For example, hydroprocessing reactor 41
may operate at the same temperature, pressure, weight hourly space
velocity (WHSV), or hydrogen-to-hydrocarbon (H.sub.2/HC) flow ratio
as hydroprocessing reactor 20, while all other conditions are not
the same.
[0075] It is contemplated that dechlorination using the second
hydroprocessing catalyst as described herein is performed in the
hydroprocessing reactor 41 without the use of chlorine sorbents,
without addition of Na.sub.2CO.sub.3 in an effective amount to
function as a dechlorinating agent, or both.
[0076] The second hydroprocessing catalyst used in the
hydroprocessing unit 41 may be any catalyst used for hydrogenation
(e.g., saturation) of olefins and aromatic hydrocarbons (e.g., a
commercially available hydrotreating catalyst). In an embodiment,
the second hydroprocessing catalyst is a cobalt and molybdenum
catalyst (Co--Mo catalyst) on an alumina support. In other
embodiments, the second hydroprocessing catalyst is a nickel and
molybdenum catalyst (Ni--Mo catalyst) on an alumina support or
tungsten and molybdenum catalyst (W--Mo catalyst) on an alumina
support. Other second catalyst embodiments may include platinum and
palladium catalyst (Pt--Pd catalyst) on an alumina support, nickel
sulphides suitable for slurry processing, molybdenum sulphides
suitable for slurry processing, nickel and molybdenum sulphides, or
combinations thereof. In embodiments where the treated hydrocarbon
stream 32 comprises one or more chloride compounds, contacting the
treated hydrocarbon carbon stream 32 with the second
hydroprocessing catalyst acts to acidify the second hydroprocessing
catalyst by chlorinating.
[0077] In embodiments, the second hydroprocessing catalyst is
chlorided using the one more chloride compounds provided to the
second hydroprocessing catalyst by the treated hydrocarbon stream
32. The one or more chloride compounds which contribute to
acidification of the second hydroprocessing catalyst may be in the
treated hydrocarbon stream 32 in concentrations disclosed herein,
e.g., 3 to 5 ppm. Chloriding the second hydroprocessing catalyst
results in a hydroprocessing catalyst which has hydrocracking sites
(chloride alumina) for hydrocracking components of the treated
hydrocarbon stream 32.
[0078] While hydrogenation in hydroprocessing reactor 41 may occur
without sulphiding, in embodiments where further hydrogenation is
desired, the second hydroprocessing catalyst may be sulphided in
the same manner as disclosed for the first hydroprocessing catalyst
in the hydroprocessing reactor 20 (e.g., treated hydrocarbon stream
32 may be spiked with sulphides via a spiking stream, a catalyst
activating stream may provide sulphides to the hydroprocessing
reactor 41, or both).
[0079] Due to hydrocracking reactions in the hydroprocessing
reactor 41, in embodiments, the polished hydrocarbon stream 43 may
contain fewer heavy hydrocarbon molecules than treated hydrocarbon
stream 32. The polished hydrocarbon product stream 43 may also
contain one or more olefins in a concentration of less than 1 wt %
based on the total weight of the polished hydrocarbon product
stream 43 (e.g., either via further hydrogenation in
hydroprocessing reactor 41, via the hydrogenation which occurs in
hydroprocessing reactor 20, or both).
[0080] The reaction product of the second hydroprocessing reactor
41 flows as effluent from the hydroprocessing reactor 41 in the
polished hydrocarbon product stream 43 to the second separator 45.
Separator 45 may be any vessel which can recover a polished
hydrocarbon stream 42 from the polished hydrocarbon product stream
43 which is fed to the separator 45. In embodiments, the polished
hydrocarbon stream 42 may be recovered by separating a polished
product (e.g., liquid product or gas product) from
chlorine-containing gas in the separator 45, and flowing the
polished product in the polished hydrocarbon stream 42 from the
separator 45.
[0081] In an embodiment, the separator 45 is a condenser which
operates at conditions which condense a portion of the polished
hydrocarbon product stream 43 into the polished product (e.g.,
liquid product or polished liquid product) while leaving
chlorine-containing compounds in the gas phase. The polished liquid
product flows from the separator 45 in polished hydrocarbon stream
42, and the chlorine-containing gas flows from the separator 45 via
gas stream 47 or from the hydroprocessing reactor 41 via stream
46.
[0082] In another embodiment, the separator 45 is a scrubbing unit
containing a caustic solution (e.g., a solution of sodium hydroxide
in water) which removes (e.g., via reaction, adsorption,
absorption, or combinations thereof) chlorine-containing gases from
the polished hydrocarbon product stream 43 to yield the polished
product (e.g., gas product or treated gas product) which flows from
the separator 45 via polished hydrocarbon stream 42 while the
chlorine-containing compounds in the gas phase flow from the
separator 45 via chloride stream 47.
[0083] In yet another embodiment, the separator 45 is a polishing
condenser in communication with one or more stages of a gas-liquid
separator which are downstream of the condenser, and a polishing
scrubbing unit containing a caustic solution. As described above,
the condenser may operate at conditions which condense a portion of
the polished hydrocarbon product stream 43 into a mid-treated
polished product while leaving chlorine-containing compounds in the
gas phase. The gases flow into the polishing scrubbing unit from
the gas-liquid separator kept downstream of the condenser, to
provide a sulphur-free and chloride-free treated gas. In such
embodiments, the mid-treated polished product may comprise C.sub.5+
(C.sub.5 and heavier) liquid hydrocarbons. The mid-treated polished
liquid product flows from the first stage of the gas-liquid
separator and experiences a pressure reduction (e.g., via a valve
or other pressure reducing device known in the art with the aid of
this disclosure) and flows into a second stage of the gas-liquid
separator, which creates an effluent gas (e.g., via flashing) which
flows to the polishing scrubbing unit for further removal of
chlorine-containing compounds from the liquid hydrocarbons. The
treated product flowing in polished hydrocarbon stream 42 flows
from the second stage of the gas-liquid separator of the separator
45 to the steam cracker 50.
[0084] In embodiments disclosed herein, no hydrogen halides and no
halogenated organic compounds are recycled to the hydroprocessing
reactor 41.
[0085] Embodiments of the disclosed processes also contemplate the
polishing zone 40 may include one or more adsorption units as
described above in series with a second hydroprocessing reactor
41/separator 45 of FIG. 2, where the adsorption unit dechlorinates
the treated hydrocarbon stream 32 and passes an intermediate stream
to the second hydroprocessing reactor 41 for further dechlorination
to yield the polished hydrocarbon stream 42 having a chloride
content required for the steam cracker 50, e.g., less than 3 ppm
chlorides. Alternatively, instead of being upstream of second
hydroprocessing reactor 41, the adsorption unit can be directly
downstream of the second hydroprocessing reactor 41.
[0086] In embodiments, the polished hydrocarbon stream 42 includes
one or more chloride compounds in a concentration of less than 3
ppm, 2 ppm, 1 ppm, or 0.5 ppm based on a total weight of the
polished hydrocarbon stream 42. It is contemplated that the one or
more chloride compounds in the polished hydrocarbon stream 42 may
be the same as some or all of the one or more chloride compounds in
the treated hydrocarbon stream 32 and/or hydrocarbon stream 12;
alternatively, it is contemplated that only some of the one or more
chloride compounds in the polished hydrocarbon stream 42 are the
same as only some of the one or more chloride compounds in the
treated hydrocarbon stream 32 and/or the hydrocarbon stream 12;
alternatively, it is contemplated that none of the one or more
chloride compounds in the polished hydrocarbon stream 42 are the
same as the one or more chloride compounds in the treated
hydrocarbon stream 32 and/or the hydrocarbon stream 12.
[0087] In additional embodiments, the polished hydrocarbon stream
42 includes the one or more olefins in a concentration of less than
1 wt % based on the total weight of the polished hydrocarbon stream
42. In embodiments, the polished hydrocarbon stream 42 may have a
reduced concentration of heavy hydrocarbon molecules compared to
the concentration of heavy hydrocarbon molecules in the treated
hydrocarbon stream 32 due to hydrocracking of at least a portion of
the heavy hydrocarbon molecules from the treated hydrocarbon stream
32 while the treated hydrocarbon stream 32 is contacted with the
second hydroprocessing catalyst in the hydroprocessing reactor 41.
In embodiments, the polished hydrocarbon stream 42 may have a
boiling end point of 370.degree. C.
[0088] In embodiments where the polished hydrocarbon stream 42
includes one or more chloride compounds in a concentration of less
than 3 ppm, the polished hydrocarbon product flowing in polished
hydrocarbon stream 42 may be fed directly to the steam cracker 50
(e.g., without fractionation or separation before flowing to the
steam cracker 50).
[0089] Steam cracker 50 generally has feed specification
requirements. First, the steam cracker 50 requires the
concentration of chloride compounds in the feed to the steam
cracker 50 to be less than 3 ppm. Second, the steam cracker 50
requires the concentration of olefins in a stream fed to the steam
cracker 50 to be less than 1 wt %. Third, the steam cracker 50
requires the boiling end point of the stream fed to the steam
cracker 50 to be 370.degree. C. The steam cracker 50 cracks
molecules or cleaves at elevated temperatures carbon-carbon bonds
of the components in the bypass stream 34 or polished hydrocarbon
stream 42 in the presence of steam to yield high value products
such as ethylene, propylene, butene, butadiene, aromatic compounds,
or combinations thereof. Likewise, in embodiments having light gas
streams 16 and/or 46, the steam cracker 50 cracks molecules or
cleaves at elevated temperatures carbon-carbon bonds of the
components in the treated light gas product (e.g., of treated
pyrolysis light gas stream 62 and/or treated hydroprocessed light
gas stream 64) in the presence of steam to yield high value
products such as ethylene, propylene, butene, butadiene, aromatic
compounds, or combinations thereof. The high value products may
flow from the steam cracker 50 via stream 52.
[0090] One or more of the pyrolysis gases (e.g., C.sub.1 to C.sub.4
gases) in the pyrolysis light gas stream 16, the C.sub.1 to C.sub.4
gases in the hydroprocessed light gas stream 36, and the C.sub.1 to
C.sub.4 gases in the polished light gas stream 46 may flow to a
light gas scrubbing unit 60. The C.sub.1 to C.sub.4 gases may be
C.sub.1 to C.sub.4 hydrocarbons. The light gas scrubbing unit 60
may be the same scrubbing unit used in embodiments of the separator
30 which include a scrubbing unit, or the light gas scrubbing unit
60 may be in addition to any scrubbing unit included in the
separator 30. As described for the scrubbing unit of the separator
30, the light gas scrubbing unit 60 may contain a caustic solution
(e.g., a solution of sodium hydroxide in water) which removes
(e.g., via reaction, adsorption, absorption, or combinations
thereof) sulphur and chlorine-containing gases from the stream
(e.g., pyrolysis light gas stream 16 and/or hydroprocessed light
gas stream 46) fed to the light gas scrubbing unit 60 and yield a
treated light gas product (e.g., treated pyrolysis light gas stream
62, treated hydroprocessed light gas stream 64, or a single treated
light gas stream which combines the treated hydroprocessed product
and treated pyrolysis product) which flows from the light gas
scrubbing unit 60 to the steam cracker 50. The removed compounds
(sulphur and/or chlorine containing gases) may flow from the
scrubbing unit 60 in stream 66.
[0091] In embodiments utilizing light gas scrubbing unit 60, the
treated pyrolysis light gas stream 62 may include one or more
sulphide and/or chloride compounds in a concentration of less than
5 ppm, 4 ppm, 3 ppm, 2 ppm, 1 ppm, or 0.5 ppm based on a total
weight of the treated pyrolysis light gas stream 62.
[0092] In embodiments utilizing scrubbing unit 60, the treated
hydroprocessed light gas stream 64 may include one or more sulphide
and/or chloride compounds in a concentration of less than 5 ppm, 4
ppm, 3 ppm, 2 ppm, 1 ppm, or 0.5 ppm based on a total weight of the
treated hydroprocessed light gas stream 64.
[0093] It is contemplated that embodiments of the disclosure may
utilize blending with a non-chlorinated stream in various locations
of the system 100. For example, a non-chlorinated stream may be
blended with bypass stream 34 to achieve the feed specification
requirements for chlorine content, olefin content, boiling end
point, sulphur content, or combinations thereof for the steam
cracker 50. In another example, a non-chlorinated stream may be
blended with treated hydrocarbon stream 32 to lower the chlorine
content, olefin content, boiling end point, sulphur content, or
combinations thereof such that subsequent treatment in the
polishing zone 40 achieves the feed specification requirements for
the steam cracker 50. In another example, a non-chlorinated stream
may be blended with polished hydrocarbon stream 42 to achieve the
feed specification requirements for chlorine content, olefin
content, boiling end point, sulphur content, or combinations
thereof for the steam cracker 50. Utilizing a blending stream
provides a mechanism by which the chloride content, sulphur
content, olefin content, and boiling end point can be adjusted to
meet feed specification requirements of the steam cracker 50
without additional capital expenditure on equipment.
[0094] The foregoing describes a system 100 which implements one or
more embodiments of a robust integrated process for the conversion
of waste plastics to high value products. The robust integrated
processes allow for operation with a single hydroprocessing reactor
20 which provides simultaneous hydrogenation, dechlorination, and
hydrocracking of components of a hydrocarbon stream 12 to
specifications which meet steam cracker 50 requirements, with the
option to further dechlorinate the treated hydrocarbon stream 32 in
a polishing zone 40, for example, when the hydroprocessing reactor
20 conditions are modified to maintain hydrogenation/saturation
efficiency at the expense of dechlorination efficiency. In such
scenarios, it is possible that chloride levels in the treated
hydrocarbon stream 32 do not meet requirements of steam cracker 50
because the concentration of one or more chloride compounds in the
treated hydrocarbon stream 32 is not less than 3 ppm, for example,
the concentration is 3-5 ppm. As such, the polishing zone 40
provides for further dechlorination to meet the chloride content
requirement of the steam cracker 50. In embodiments where the
polishing zone 40 is a second hydroprocessing reactor 41,
hydrocracking, hydrogenation, or both, of the components of the
treated hydrocarbon stream 32 may also occur in addition to
dechlorination.
[0095] When operating with a single hydroprocessing step in
hydroprocessing reactor 20, the treated hydrocarbon stream 32 is
suitable for feeding directly to steam cracker 50, without
separations or fractionations of the treated hydrocarbon product.
When operating with use of the polishing zone 40, the treated
hydrocarbon stream 32 is "polished" to yield polished hydrocarbon
stream 42 without fractionation or further separation of the
polished hydrocarbon stream 42.
[0096] Catalyst activity of the hydroprocessing catalyst can be
initiated and/or maintained simultaneously with the simultaneous
hydrogenation, dechlorination, and hydrocracking by using streams
of the compositions disclosed herein which feed to a
hydroprocessing reactor.
[0097] The hydroprocessing catalyst in hydroprocessing reactor 20
may be the same or different from the hydroprocessing catalyst in
the hydroprocessing reactor 41. In embodiments where the
hydroprocessing catalyst is the same for both first hydroprocessing
reactor 20 and second hydroprocessing reactor 41, the operating
conditions of the reactors 20 and 41 may be adjusted to achieve the
desired feed specifications for steam cracker 50. In addition,
catalyst sulphiding may be adjusted. For example, first
hydroprocessing catalyst in the hydroprocessing reactor 20 may be
sulphided as disclosed herein while the second hydroprocessing
catalyst in the hydroprocessing reactor 41 is not sulphided via the
techniques disclosed herein. By not sulphiding the second
hydroprocessing catalyst, the first hydroprocessing catalyst can be
tuned for simultaneous hydrogenation, dechlorination, and
hydrocracking while the second hydroprocessing catalyst can be
tuned for dechlorination and hydrocracking (some hydrogenation may
occur; however, the concentration of sulphided metal sites which
provide for hydrogenation by the second hydroprocessing catalyst is
less than the concentration of sulphided metal sites provided by
the first hydroprocessing catalyst). The robustness of the
disclosed processes may also allow for intermittent sulphiding of
the second hydroprocessing catalyst in the hydroprocessing reactor
41 in order to adjust the degree of hydrogenation in the second
hydroprocessing reactor as a result of fluctuations in the
hydrogenation efficiency in the first hydroprocessing reactor
20.
[0098] Examples provided below demonstrate the various embodiments
of the pyrolysis process for generating a pyrolysis oil or
hydrocarbon stream, not limited by the equipment used. These
examples are for high severity pyrolysis process carried out at
temperatures of 450.degree. C. to 750.degree. C., low severity
pyrolysis process carried out at 250.degree. C. to 450.degree. C.,
hydrogen or hydrogen donor assisted (hydropyrolysis) processes
carried out at both the above severities as well as use of a
catalyst recipe and a combination of sand and catalyst as a
catalyst recipe. Though these examples are provided for fluidized
beds where in the heat transfer and catalyst/feed contact are good,
directionally the same type of results can be obtained with other
types of pyrolysis equipment as described herein.
[0099] Also, as is demonstrated in the examples below and discussed
above, it has been found that hydrocracking of olefins and heavy
hydrocarbon molecules contained in a hydrocarbon stream occurs
using a hydroprocessing catalyst at the conditions disclosed
herein. The olefins are hydrogenated in addition to being
hydrocracked. Moreover, chloride compounds contained in the
hydrocarbon stream are removed using hydroprocessing catalyst.
Hydrocracking according to the embodiments disclosed herein can
occur over the operating pressures disclosed herein for
hydroprocessing reactor 20, including those low pressures
demonstrated in the examples. Embodiments of the processes
disclosed herein meet the boiling end point of 370.degree. C.
required for steam crackers. Moreover, the disclosed embodiments
demonstrate that about 30 wt % of the heavy hydrocarbon molecules
of a hydrocarbon stream can undergo hydrocracking at the conditions
disclosed herein. When the hydrocarbon stream contains plastic
and/or tire pyrolysis oil, the heavier ends of the pyrolysis oil
are hydrocracked. Increased levels of paraffins due to the
hydrocracking ability of the processes disclosed herein can result
in a higher production of propylene in steam crackers. LPG gases
are not liberated in the disclosed processes until the temperature
of the one or more catalyst beds in the hydroprocessing reactor 20
reaches about 400.degree. C. Gas product formation is minimized,
which is useful for existing plants which are constrained on the
gas flow rate to the gas compressor section. In the disclosed
embodiments, the production of methane and ethane is also low.
[0100] Dechlorination according to the embodiments disclosed herein
can occur over the operating temperature ranges disclosed herein
for the hydroprocessing reactor 20, including operating
temperatures in the low-end of the temperature ranges disclosed
herein. Removal of chloride compounds to less than 1 ppm occurs at
temperatures below 350.degree. C. Moreover, achieving sub-ppm
chloride compound concentrations is possible with initial chloride
content in the hydrocarbon stream 12 of 1,000 ppm or more. Moreover
still, removal of chloride compounds is effective for different
types and classes of chlorides present in the hydrocarbon stream
12. When the hydroprocessing reaction is conducted at temperatures
at or above 350.degree. C., it has been found that the treated
hydrocarbon product contains 3 ppm or higher chloride content. In
such cases, blending with a non-chlorinated stream can be utilized.
For example, the treated hydrocarbon product stream 32, bypass
stream, 34, polished hydrocarbon stream 42, or combinations thereof
can be blended with a non-chlorinated stream in such proportions to
make the combined blended treated hydrocarbon stream meet the steam
cracker feed specifications.
[0101] Operation at low temperatures (e.g., less than 350.degree.
C.) also has an added advantage of corrosion mitigation of the
reactor metallurgy. For most metals and alloys used in the
commercial reactors, corrosion rates start to increase at reactor
temperatures over 300.degree. C. It has been found that the
efficiency of dechlorination according to the disclosed embodiments
is good at reactor temperatures below 350.degree. C., and the
dechlorination process works with a sulphided Co--Mo catalyst on an
alumina support even as low as 260.degree. C., with the chlorides
in the treated product being less than 1 ppm. Thus, the metallurgy
corrosion issue is mitigated and longer equipment life is possible
while achieving dechlorination to levels desirable for feed to
steam cracker 50. The processes disclosed herein have been
demonstrated to work at pressures as low as 20 barg, which is a
less severe condition than the conditions typically employed with a
commercial hydrotreating catalyst. Ability to operate at lower
pressures reduces the required pressure rating for process vessels
(e.g., the hydroprocessing reactor 20) and provides an opportunity
for reduced investment costs.
[0102] The disclosed embodiments also demonstrate olefins in the
hydrocarbon product are reduced typically to less than 1 wt % of
the treated hydrocarbon stream 32 from a feed olefin concentration
of 20 wt % or more in the hydrocarbon stream 12.
[0103] Thus, the disclosed embodiments achieve the pyrolysis of
plastics and also requirements of chloride content, olefin content,
and boiling end point of the feed for a steam cracker starting from
a plastic pyrolysis feed.
EXAMPLES
[0104] The subject matter having been generally described, the
following examples are given as particular embodiments of the
disclosure and to demonstrate the practice and advantages thereof.
It is understood that the examples are given by way of illustration
and are not intended to limit the specification of the claims to
follow in any manner.
[0105] Examples 1 to 9 were conducted in a fixed bed reactor
located inside a 3-zone split-tube furnace. The reactor internal
diameter was 13.8 mm and had concentrically located bed thermowell
of 3 mm outer diameter. The reactor was 48.6 cm long. Commercial
hydroprocessing catalyst of Co--Mo on alumina (8 g bone dry weight)
was broken along the length to particles of 1.5 mm long and diluted
with SiC in the ratio of 60% SiC to 40% catalyst to give a mean
particle diameter of 0.34 mm. This was done to avoid slip through
of the chlorides due to wall slip or channeling in the small
diameter reactor. Pre-heating bed and post-catalyst inert beds was
provided in the form of 1 mm glass beads. The catalyst bed
temperature was controlled to isothermal by varying the controlled
furnace zone skin temperatures. The catalyst was sulphided using 3
wt % S in hexadecane (S was introduced as dimethyl disulphide).
Liquid feed (i.e., the hydrocarbon stream) was fed through a
metering pump and H.sub.2 gas was fed using a mass flow controller.
The reactor effluent (i.e., the hydrocarbon product) gases were
cooled to condense out the liquids (i.e., the treated hydrocarbon
stream in the form of a liquid product) under pressure while
allowing non-condensed gases (e.g., containing chloride(s),
chlorine, hydrogen sulphide, or combinations thereof) to separate.,
Following liquid condensation, the pressure of the liquids was
reduced and effluent gas flow was measured using a drum-type wet
gas meter. The effluent gas flow was analyzed using a refinery gas
analyzer (a custom gas analyzer from M/s AC Analyticals BV). The
liquid product olefin content was determined using a Detailed
Hydrocarbon Analyzer GC (DHA) and a boiling point characterization
was obtained using a SIMDIS GC. The liquid product chloride content
was measured using a Chlora M-series analyzer (monochromatic
wavelength dispersive X-ray Fluorescence technique, ASTM
D7536).
Example 1
[0106] In Example 1, a hydrocarbon feed mixture was prepared by
mixing 30 wt % n-hexadecane, 10 wt % i-octane, 20 wt % 1-decene, 20
wt % cyclohexane, and 20 wt % ethyl benzene. Dimethyl disulphide,
2-chloropentane, 3-chloro-3-methyl pentane, 1-chlorohexane,
(2-chloroethyl) benzene, and chlorobenzene were then added to give
205 ppmw organic chlorides and a sulphur content of 2 wt % S in the
combined feed mixture. This combined feed mixture was used as the
hydrocarbon stream which was contacted with the hydroprocessing
catalyst in the packed bed reactor as mentioned above in the
presence of H.sub.2 at conditions of 280.degree. C. reactor
temperature, 60 barg reactor pressure, 0.92 hr.sup.-1 WHSV, and 414
NL/L H.sub.2/HC flow ratio. The liquid product (i.e., the treated
hydrocarbon stream) was analyzed in a DHA wherein molecules lighter
than C.sub.13 are injected into the GC column and heavier than
C.sub.13 are flushed out. The normalized composition of liquid
product as measured by DHA was paraffins (26.24 wt %), i-paraffins
(17.28 wt %), olefins (0 wt %), naphthenes (33.61 wt %), and
aromatics (22.88 wt %). SIMDIS analysis of liquid product indicates
that 78 wt % of the liquid product boils at 180.degree. C., and
immediately at 79 wt %, the boiling point shifts to 286.degree. C.;
indicating that 22 wt % (i.e. 100-78=22) of the liquid product is
hexadecane. This implies out of 30 wt % hexadecane in the feed
(calculated based on the feed excluding chloride and sulphides,
since dimethyl disulphide is converted to gases, the chloride
compounds are dechlorinated so as to contribute less than 0.5 wt %
of the product), 8 wt % of hexadecane was hydrocracked to lower
products. As mentioned before, this 22 wt % does not get analyzed
in DHA. This 22 wt % hexadecane unaccounted in DHA composition is
added to the liquid product analyzed by DHA (DHA composition
multiplied by 0.78 fraction that was injected into DHA) and the
resulting composition of the liquid product is 42.47 wt %
paraffins, 13.48 wt % i-paraffins, 0 wt % olefins, 26.21 wt %
naphthenes and 17.84 wt % aromatics. In addition, the chloride
content of the liquid product was 0.09 ppmw.
[0107] Example 1 demonstrates it is possible to simultaneously
dechlorinate, hydrogenate, and hydrocrack a PIONA hydrocarbon
stream containing heavy hydrocarbon molecules (e.g., hexadecane), a
chloride content of more than 200 ppm, and an olefin content of 20
wt % (calculated based on the feed excluding chloride and
sulphides) such that a portion of the heavy hydrocarbon molecules
are hydrocracked, chloride content is reduced to less than 1 ppm,
and olefins are completely removed (0 wt % in the liquid product).
Comparing feed and liquid product compositions, it can be said that
paraffins, i-paraffins, and naphthenes have increased in
concentration, while aromatics have reduced in concentration and
olefins were completely depleted. This clearly indicates
hydrocracking of hexadecane as well as hydrocracking of olefins in
feed. Thus, Example 1 additionally demonstrates olefins are
hydrocracked in addition to being hydrogenated.
[0108] The DHA analysis summary by carbon number for the liquid
product is shown below:
TABLE-US-00001 n- i- Ole- Naph- Aro- Paraffins, Paraffins, fins,
thenes, matics, Total, Carbon No. wt % wt % wt % wt % wt % wt % 2 3
4 0.015 0.015 5 0.012 0.012 6 0.016 0.18 27.136 0.048 27.217 7 0 8
0.145 14.226 0.547 21.979 36.896 9 0.079 5.901 0.834 6.814 10 26.01
2.93 0.039 11 12 Total, wt % 26.221 17.268 35.584 22.86 99.933
Unknown 0.053 Heavies 0.013
Example 2
[0109] Example 2 explores the effect of operating pressure on
hydrocracking performance. A hydrocarbon feed mixture was prepared
by mixing 30 wt % n-hexadecane, 10 wt % i-octane, 20 wt % 1-decene,
20 wt % cyclohexane, and 20 wt % ethyl benzene. Dimethyl
disulphide, 2-chloropentane, 3-chloro-3-methyl pentane,
1-chlorohexane, (2-chloroethyl) benzene, and chlorobenzene were
then added to give 205 ppmw organic chlorides and a sulphur content
of 2 wt % S in the combined feed mixture. This combined feed
mixture was used as a hydrocarbon stream which was contacted the
sulphided hydroprocessing catalyst in the packed bed reactor as
mentioned above in the presence of H.sub.2 at conditions of
300.degree. C. reactor temperature, 0.92 hr.sup.-1 WHSV, and 414
NL/L H.sub.2/HC flow ratio. Three different pressure conditions
were studied: 60 barg for Example 2A, 20 barg for Example 2B, and
10 barg for Example 2C. The liquid products (i.e., the treated
hydrocarbon streams) for each of Examples 2A to 2C were analyzed
using SIMDIS, and the results are shown below:
TABLE-US-00002 Example 2A Example 2B Example 2C Liquid Product
Liquid Product Liquid Product 60 barg 20 barg 10 barg Cut, T, Cut,
T, Cut, T, wt % .degree. C. wt % .degree. C. wt % .degree. C. 0
61.4 0 52.0 0 61.4 5 72.0 5 61.4 5 72.0 10 72.0 10 72.0 10 72.0 15
72.0 15 72.0 15 72.0 20 72.0 20 72.0 20 72.0 25 72.0 25 72.0 25
72.0 30 87.6 30 72.0 30 72.0 35 87.6 35 72.0 35 87.6 40 87.6 40
87.6 40 87.6 45 87.6 45 87.6 45 132.0 50 87.6 50 134.6 50 137.2 55
129.4 55 137.2 55 139.8 60 134.6 60 139.8 60 139.8 65 139.8 65
142.4 65 161.2 70 170.6 70 163.2 70 173.8 75 176.0 75 175.4 75
177.0 79 177.6 80 179.0 78 178.0 80 278.6 83 180.6 80 271.6 85
289.2 85 279.6 85 288.2 90 292.0 90 291.0 90 291.6 95 294.0 95
294.6 95 294.0 99 295.4 99 296.8 99 295.4 100 295.6 100 297.0 100
295.6
[0110] The DHA analysis summary of the liquid product boiling below
240.degree. C. is shown below:
TABLE-US-00003 Example n-Paraffins, i-Paraffins, Olefins,
Naphthenes, Aromatics, Unknown, Heavies, No. wt % wt % wt % wt % wt
% wt % wt % 2A 22.507 19.415 0.183 31.159 17.912 0.131 0.693 2B
19.544 21.513 0.047 30.490 27.465 0.315 0.626 2C 21.368 21.281
0.000 24.687 30.719 0.355 1.591
[0111] The results provided in the tables above indicate that 20 wt
% or less of the liquid product for each of Examples 2A to 2C boils
in the hexadecane boiling point range. In contrast, the feed
contained 30 wt % hexadecane (calculated based on the feed
excluding chlorides and sulphides). Hence, at all pressures,
hydrocracking of heavy hydrocarbon molecules (e.g., hexadecane)
using a hydrogenation catalyst is demonstrated.
[0112] The corresponding chloride contents of the liquid product
(i.e., treated hydrocarbon stream) at 60 barg, 20 barg, and 10 barg
were respectively 0.11 ppmw, 0.09 ppmw, and 0.12 ppmw.
[0113] The liquid product (analyzed in DHA) for Example 2A (60
barg) contained 0.183 wt % olefins, for Example 2B (20 barg)
contained 0.047 wt %, and for Example 2C (10 barg) contained 0 wt %
olefins. At lower pressures, a significant increase in aromatics is
observed.
[0114] Example 2 demonstrates it is possible to simultaneously
dechlorinate and hydrocrack a PIONA hydrocarbon stream containing
heavy hydrocarbon molecules (e.g., hexadecane) and a chloride
content of more than 200 ppmw such that a portion of the heavy
hydrocarbon molecules are hydrocracked and chloride content is
reduced to less than 1 ppm for all pressures tested.
Example 3
[0115] In Example 3, a hydrocarbon feed mixture was prepared to
contain 30 wt % n-hexadecane, 10 wt % i-octane, 20 wt % 1-decene,
20 wt % cyclohexane and 20 wt % ethyl benzene. To this the organic
chlorides mentioned in Example 2 above were added along with
dimethyl disulphide to give 205 ppm organic chlorides and 2 wt % S
in the mixture. This feed was used as a hydrocarbon stream which
was contacted with the sulphided hydroprocessing catalyst in the
packed bed reactor as mentioned above in the presence of H.sub.2 at
conditions of 260.degree. C. reactor temperature, 60 barg reactor
pressure, 0.92 hr.sup.-1 WHSV and 414 NL/L H.sub.2/HC flow ratio.
The liquid product (i.e., the treated hydrocarbon stream) contained
0.1 ppmw chloride.
[0116] Example 3 demonstrates the effective removal of chloride
compounds from a hydrocarbon stream at very low temperatures.
Example 4
[0117] In Example 4, a feed was prepared by mixing plastic
pyrolysis oil (36.3 g) with n-hexadecane (240 g), and then adding
dimethyl disulphide (the sulphide) and 1-chlorohexane (the chloride
compound) to give a sulphur content of 2.34 wt % and 836 ppm
chloride in the feed. This feed was used as a hydrocarbon stream
which was contacted with the hydroprocessing catalyst in the packed
bed reactor as mentioned above in the presence of H.sub.2 under
several operating conditions as provided in the table below:
TABLE-US-00004 T, P, WHSV, H.sub.2/HC, Cl, ppm in .degree. C. barg
hr.sup.-1 NL/L liquid product 300 60 0.92 414 0.32 300 40 0.92 414
0.87 350 40 0.92 414 3.42 400 40 0.92 414 3.15
[0118] The gas composition of the reactor effluents is as below and
indicates LPG gases are formed at temperatures close to 400 deg
C.:
TABLE-US-00005 Cl, ppm in n- i- T, P, WHSV, H.sub.2/HC, liquid
H.sub.2, CH.sub.4, C.sub.2H.sub.6, C.sub.3H.sub.8, C.sub.4H.sub.10,
C.sub.4H.sub.10, .degree. C. barg hr.sup.-1 NL/L product mole %
mole % mole % mole % mole % mole % 300 40 0.92 414 0.87 96.63 3.25
0.12 -- -- -- 350 40 0.92 414 3.42 95.32 4.48 0.2 -- -- -- 400 40
0.92 414 3.15 93.96 5.21 0.45 0.23 0.08 0.07
[0119] Example 4 demonstrates it is possible to dechlorinate a
hydrocarbon stream containing plastic pyrolysis oil and having
chloride compounds from a chloride content of more than 800 ppm
chlorides to less than 5 ppm in the liquid product. As can be seen
from the above table, the chloride content of the liquid product
(i.e., the treated hydrocarbon stream) increases when the reactor
bed temperature is increased to at or above 350.degree. C. At
temperatures below 350.degree. C., Example 4 demonstrates removal
of chloride compounds to chloride contents less than 3 ppm, and
even sub-ppm levels.
Example 5
[0120] In Example 5, a feed was prepared by mixing plastic
pyrolysis oil (36.3 g) with n-hexadecane (240 g), and then adding
dimethyl disulphide (the sulphide) and 1-chlorohexane (the chloride
compound) to give a sulphur content of 2.34 wt % and 836 ppm
chloride in the feed. This feed was used as a hydrocarbon stream
which was contacted with the hydroprocessing catalyst (chlorinated
and sulphided Co--Mo on alumina) in the packed bed reactor as
mentioned above in the presence of H.sub.2 under operating
conditions of 40 barg reactor pressure, 400.degree. C. reactor bed
temperature, 0.92 hr.sup.-1 WHSV, and a hydrogen to hydrocarbon
ratio of 414 NL/L. The product from this reactor had 2.94 ppmw
chloride. A polishing step was performed by mixing 5 g of the
product with 1 g of gamma alumina (the adsorbent) at room
temperature for 1 hr to monitor adsorptive performance. The
supernatant from this polishing step was analyzed for chloride
content, which was found to have 1.46 ppmw chloride. Thus a
chloride content from 2.94 ppmw obtained from a near end-of-run
condition for the hydroprocessing catalyst (a border-line value for
steam cracker feed) was reduced in the polishing step to an
acceptable chloride level of 1.46 ppmw.
Example 6
[0121] In Example 6, a hydrocarbon feed mixture was prepared to
contain 30 wt % n-hexadecane, 10 wt % i-octane, 20 wt % 1-decene,
20 wt % cyclohexane, and 20 wt % ethyl benzene. To this were added
dimethyl disulphide, 2-chloropentane, 3-chloro-3-methyl pentane,
1-chlorohexane, (2-chloroethyl) benzene and chlorobenzene to give
205 ppm organic chlorides and 2 wt % S in the mixture. A
dechlorination step was performed by mixing 5 g of this feed
mixture with 1 g of gamma alumina at room temperature for 1 hr to
monitor adsorptive performance. The supernatant was measured for
its chloride content, which was found to be 191 ppmw.
[0122] Example 6 demonstrates that dechlorination by adsorption for
hydrocarbon streams contemplated in this disclosure as feeding to a
first hydroprocessing reactor does not effectively reduce the
chloride content to levels required for steam crackers. However,
Example 6 and Example 5 demonstrate adsorption units may be useful
in the disclosed polishing zone, alone or upstream or downstream of
a second hydroprocessing reactor.
Example 7
[0123] In Example 7, a feed was prepared by adding dimethyl
disulphide (the sulphide) and 2-chloropentane, 3-chloro-3-methyl
pentane, 1-chlorohexane, (2-chloroethyl) benzene, and chlorobenzene
(the chloride compounds) to n-hexadecane to give a sulphur content
of 2 wt % in the mixture and a chloride content of 1,095 ppm in the
mixture. Each of the chloride compounds contributed approximately
220 ppm to the feed mixture. This feed was used as a hydrocarbon
stream which was contacted with the hydroprocessing catalyst in the
packed bed reactor as mentioned above in the presence of H.sub.2 at
300.degree. C. reactor bed temperature, 40 barg reactor pressure,
414 NL/L H.sub.2/HC flow ratio, and 0.92 hr.sup.-1 weight hourly
space velocity (WHSV). The chloride content of the liquid product
(i.e., treated hydrocarbon stream) was 0.23 ppmw.
[0124] Example 7 demonstrates it is possible to dechlorinate a
hydrocarbon stream containing no olefins and chloride compounds
from a chloride content of about 1,100 ppm chlorides to the sub-ppm
level in the in the liquid product.
Example 8
[0125] In Example 8, a hydrocarbon feed mixture was prepared by
mixing 30 wt % n-hexadecane, 10 wt % i-octane, 20 wt % 1-decene, 20
wt % cyclohexane, and 20 wt % ethyl benzene. Dimethyl disulphide,
2-chloropentane, 3-chloro-3-methyl pentane, 1-chlorohexane,
(2-chloroethyl) benzene, and chlorobenzene were then added to give
1,100 ppmw organic chlorides and a sulphur content of 2 wt % S in
the combined feed mixture. This combined feed mixture was used as
the hydrocarbon stream which was contacted with the hydrogenating
catalyst in the packed bed reactor as mentioned above in the
presence of H.sub.2 at conditions of 300.degree. C. reactor
temperature, 40 barg reactor pressure, 0.92 hr.sup.-1 WHSV, and 414
NL/L H.sub.2/HC flow ratio. The liquid product contained 0.23 ppmw
chlorides and paraffins of 22.569 wt %, paraffins of 19.752 wt %,
olefins of 0.114 wt %, naphthenes of 33.242 wt %, aromatics of 23.7
wt %, unknowns of 0.16 wt % and heavies of 0.463 wt % as per DHA
analysis. This again demonstrates the dechlorination of liquid at
much higher chloride concentrations.
[0126] The SIMDIS of liquid product resulted in the following
distribution and also indicated hydrocracking:
TABLE-US-00006 Cut, T, wt % .degree. C. 0 61.4 5 72 10 72 15 72 20
72 25 72 30 72 35 72 40 87.6 45 87.6 50 132 55 134.6 60 137.2 65
142.4 70 170.6 75 175.4 80 177 85 287 90 290 95 292.2 99 293.4 100
293.8
[0127] DHA Group type analysis of the liquid product by carbon
number (in wt %) is as below:
TABLE-US-00007 n-Paraffins, i-Paraffins, Olefins, Naphthenes,
Aromatics, Total, Carbon No. wt % wt % wt % wt % wt % wt % 2 0 3 0
4 0.008 0.056 0.064 5 0.033 0.021 0.054 6 0.035 0.05 26.925 0.072
27.082 7 0.013 0.008 0.012 0.033 8 0.287 13.892 0.951 21.97 37.1 9
0.172 0.114 5.265 1.623 7.174 10 22.161 5.553 0.089 0.035 27.838 11
0.025 0.025 12 0.007 0.007 Oxygenates Heavies 0.464 Unknown 0.16
Total, wt % 100.001
[0128] In this example, the yield of liquid products was 95.5 wt %
of the total products. The balance was gas products.
Example 9
[0129] In Example 9, a n-hexadecane feed mixture was prepared by
mixing n-hexadecane with dimethyl disulphide, 2-chloropentane,
3-chloro-3-methyl pentane, 1-chlorohexane, (2-chloroethyl) benzene,
and chlorobenzene to give 1,034 ppm of chlorides and 2 wt % Sulphur
in the feed. This combined feed mixture was used as the hydrocarbon
stream which was contacted with the hydrogenating catalyst in the
packed bed reactor as mentioned above in the presence of H.sub.2 at
conditions of 300.degree. C. reactor temperature, 40 barg reactor
pressure, 0.92 hr.sup.-1 WHSV, and 414 NL/L H.sub.2/HC flow ratio.
The liquid product contained 0.3 ppmw chlorides and paraffins of
22.569 wt %, i-paraffins of 19.752 wt %, olefins of 0.114 wt %,
naphthenes of 33.242 wt %, aromatics of 23.7 wt %, unknowns of 0.16
wt % and heavies of 0.463 wt % as per DHA analysis. This again
demonstrates the dechlorination of liquid at high chloride
concentrations to sub-ppm levels.
[0130] The SIMDIS of liquid product resulted in the following
distribution and also indicated hydrocracking to the extent of
about 15 wt % on a chloride and sulphide-free feed basis:
TABLE-US-00008 Cut Temp (wt %) (.degree. C.) 0 61.4 5 129.4 10
161.2 13 170.6 14 260.2 15 272.4 20 285.2 25 287.4 30 289 35 290.2
40 291.2 45 292.2 50 293 55 293.8 60 294.4 65 295 70 295.6 75 296.2
80 297 85 297.4 90 297.8 95 298.2 99 298.8 100 310.8
[0131] DHA Group type analysis of the liquid product by carbon
number (in wt %) is as below and indicates conversion of
n-hexadecane to various PIONA components:
TABLE-US-00009 n-Paraffins, i-Paraffins, Olefins, Naphthenes,
Aromatics, Total, Carbon No. wt % wt % wt % wt % wt % wt % 2 0.005
0.005 3 0.006 0.006 4 0.019 0.098 0.118 5 0.068 0.064 0.132 6 0.072
0.133 25.607 0.11 25.922 7 0.016 0.034 0.051 8 0.401 13.31 1.268
21.179 36.157 9 0.133 0.136 5.53 2.449 8.248 10 19.165 8.19 0.213
0.049 27.617 11 0.03 0.03 12 0.011 0.011 Oxygenates Heavies 1.413
Unknown 0.29 Total, wt % 100
Example 10
[0132] Example 10 shows a high severity operation for the pyrolysis
unit 10. An amount of 1.5 g of plastics feed and 9 g of catalyst
mixture having a composition comprised of 37.5 wt. % ZSM-5
catalyst, with the remainder being spent FCC catalyst, were used in
pyrolysis conversions in a fluidized bed reactor. Details regarding
the experimental facility for Example 10 are described in U.S.
Patent Publication No. 2014/0228606A1, which is incorporated herein
by reference in its entirety. The mixed plastics feed had the
following composition:
TABLE-US-00010 Amount, Material wt % HDPE 19 LDPE 21 PP 24
C.sub.4-LLDPE 12 C.sub.6-LLDPE 6 PS 11 PET 7
[0133] The reaction temperature at start of reaction was
670.degree. C. The one-minute average bed temperatures achieved was
569.6.degree. C. The Catalyst/Feed (C/F) ratio was 6. Fluidization
N.sub.2 gas flow rate used was 175N cc/min. Overall aromatic and
liquid i-paraffin product yields and aromatic and liquid i-paraffin
content in liquid product boiling below 240.degree. C. were 31.6 wt
% and 5.76 wt %, respectively. Their respective concentrations in
the liquid product boiling below 240.degree. C. was 74.72 wt % and
13.22 wt %. The yield of light gas olefins, i.e., the sum of yields
of ethylene, propylene and butenes was 32.69 wt %, and the total
yield of gas products was 45.17 wt %.
[0134] The DHA analysis of the liquid product boiling below
240.degree. C. was:
TABLE-US-00011 n-Paraffins, i-Paraffins, Olefins, Naphthenes,
Aromatics, Total, Carbon No. wt % wt % wt % wt % wt % wt % 5 0.013
0.02 0.169 0.031 0.233 6 0.101 0.219 1.031 0.318 5.28 9.113 7 0.254
1.243 2.267 0.665 17.188 21.618 8 0.544 2.703 0.354 1.125 30.339
35.066 9 0.22 3.98 0.107 1.44 10.95 16.70 10 0.12 2.07 0.217 3.89
6.30 11 0.10 2.53 0.299 1.53 4.39 12 0.05 0.46 3.37 3.88 13 0.03
0.03 Unknown 2.69 Total, wt % 1.42 13.22 3.928 4.03 74.72 97.32
Total, wt % on 6.3 58.5 17.4 17.8 Aromatics- Free Basis
[0135] The yield of heavy products boiling above 370.degree. C. was
0.86 wt %.
Example 11
[0136] Example 11 shows a high severity operation for the pyrolysis
unit 10, operated in a hydrogen-assisted hydropyrolysis mode. An
amount of 1.5 g of mixed plastics was mixed with 9 g of a catalyst
mixture comprising 62.5 wt % spent FCC catalyst and 37.5 wt % ZSM-5
zeolite catalyst. The combined mixture was then fed to the
fluidized bed reactor described in Example 1. The plastic feed was
in the form of a 200 micron plastic powder. A mixture of 10%
H.sub.2 in N.sub.2 was employed as the carrier gas at a flow rate
of 175 N cc/min.
[0137] Studies were conducted by maintaining the reactor bed
temperature, before feed and catalyst mixture was introduced, at
600.degree. C., 635.degree. C., and 670.degree. C., respectively,
i.e., at 3 different starting temperatures. Studies were also
conducted at the same conditions as before with 100% N.sub.2 as
carrier gas. For each of the temperature conditions studied, a new
set of catalyst and feed mixture was prepared and used.
[0138] The tables below summarize the experimental findings, where
all study used a mixed plastic feed and spent FCC (62.50 wt
%)+ZSM-5 zeolite catalyst (37.5 wt %) as the pyrolysis
catalyst:
TABLE-US-00012 Hydro- Hydro- Hydro- pyrolysis 1 Pyrolysis 1
pyrolysis 2 Pyrolysis 2 pyrolysis 3 Pyrolysis 3 Feed Weight 1.50
1.50 1.50 1.50 1.50 1.50 Transferred, g Bone-Dry Catalyst 9.05 8.95
9.05 9.05 9.01 8.95 Feed, g C/F ratio, g/g 6.03 6.0 6.03 6.03 6.00
6.0 Reaction Start 600 600 635 635 670 670 Temperature, .degree. C.
1 min Avg. Reactor 482 472 525 525 567 570 Bed Temperature,
.degree. C. Yield, wt %, based on H.sub.2-free product Methane 0.92
0.40 1.00 0.56 3.20 0.99 Ethane 0.87 0.43 0.73 0.52 0.69 0.74
Ethylene 6.17 3.68 6.50 5.07 6.36 5.78 Carbon Dioxide 1.29 1.63
1.54 1.93 1.85 1.91 Propane 3.90 4.26 3.15 3.58 3.11 3.49 Propylene
12.76 11.05 13.63 12.93 14.67 14.75 i-Butane 4.56 4.99 3.85 4.75
3.77 3.53 n-Butane 2.67 1.84 2.07 1.57 1.31 1.41 t-2-Butene 3.16
2.67 3.10 2.89 2.99 3.01 1-Butene 1.75 1.63 1.79 1.79 1.90 2.01
i-Butylene 4.68 4.55 4.56 4.76 4.72 4.97 c-2-Butene 2.22 1.92 2.19
2.09 2.14 2.21 Carbon Monoxide 1.25 0.10 0.35 0.00 0.80 0.25
Gasoline 43.83 45.34 41.66 42.42 42.11 49.30 Diesel 5.75 9.14 7.55
8.37 4.73 5.16 Heavies 0.56 1.64 0.78 0.88 0.49 0.86 Coke 4.67 4.73
5.55 5.88 5.12 5.64
[0139] Overall, yield of gas products has increased and liquid
products have decreased indicating higher conversions to lighter
products.
TABLE-US-00013 Hydro- Hydro- Hydro- pyrolysis 1 Pyrolysis 1
pyrolysis 2 Pyrolysis 2 pyrolysis 3 Pyrolysis 3 C.sub.1-C.sub.4
Yield, wt % 45.2 39.1 44.5 42.5 47.5 45.0 Liquid Yield, wt % 50.1
56.1 50.0 51.7 47.3 49.3 Coke Yield, wt % 4.7 4.7 5.6 5.9 5.1
5.6
[0140] As can be seen, the yield of light gas olefins per unit
amount of coke deposited on the catalyst is higher in the case of
hydropyrolysis. This implies that more light gas olefins would be
produced in a circulating fluid catalytic cracking type of unit. In
these units, performance is compared on a constant coke yield
basis. This is because the amount of coke burnt off in the
regenerator is limited by the air availability in the regenerator
and as a result the regenerated catalyst returned back to the riser
would have more or less coke on it which would in turn affect its
activity in the riser.
[0141] The total aromatics as well as C.sub.6-C.sub.8 aromatics
yield per unit amount of coke deposited is also higher in the case
of hydropyrolysis. This implies in hydropyrolysis more aromatic
products would be produced in a circulating fluid catalytic
cracking type of unit.
TABLE-US-00014 Hydro- Hydro- Hydro- pyrolysis 1 Pyrolysis 1
pyrolysis 2 Pyrolysis 2 pyrolysis 3 Pyrolysis 3 Total Aromatics
32.42 31.39 32.81 31.83 35.09 32.35 Yield Boiling Below 240.degree.
C., wt % C.sub.6-C.sub.8 Aromatics 23.81 23.20 24.44 22.63 26.33
22.87 Yield, wt % Total 6.9 6.6 5.9 5.4 6.9 5.7 Aromatics/Coke, wt
ratio (C.sub.6-C.sub.8 5.1 4.9 4.4 3.9 5.1 4.1 Aromatics)/Coke, wt
ratio Light gas 6.6 5.4 5.7 5.0 6.4 5.8 olefins/Coke, wt ratio
C.sub.4 Olefins, wt % 11.81 10.76 11.64 11.54 11.77 12.20 C.sub.3
Olefins, wt % 12.76 11.05 13.63 12.93 14.67 14.75 C.sub.2 Olefins,
wt % 6.17 3.68 6.50 5.07 6.36 5.78 Total Olefins, wt % 30.74 25.49
31.77 29.54 32.80 32.72
[0142] To summarize, more high value chemicals (i.e. light gas
olefins and aromatics) are produced in hydropyrolysis as compared
to pyrolysis done without use of hydrogen carrier gas.
[0143] Additional benefits include: [0144] a. increased olefinicity
of product gases; [0145] b. increased ratio of propylene/propane as
compared to ethylene to ethane and butenes/butanes; [0146] c. lower
hydrogen transfer index (i.e. ratio of C.sub.3 and C.sub.4
saturates/C.sub.3 olefins) in hydropyrolysis as compared to use of
nitrogen only as carrier gas; and [0147] d. more C.sub.4
iso-olefins are produced in as compared to 1-butene in
hydropyrolysis (i.e. isomerization index is lower).
TABLE-US-00015 [0147] Hydro- Hydro- Hydro- pyrolysis 1 Pyrolysis 1
pyrolysis 2 Pyrolysis 2 pyrolysis 3 Pyrolysis 3 Hydrogen Transfer
0.87 1.00 0.67 0.77 0.56 0.57 Index (HTI) Isomerization 0.174 0.178
0.182 0.184 0.192 0.197 Coefficient C.sub.2 Olefin/C.sub.2
Saturated 7.1 8.6 8.9 9.8 9.2 7.9 Hydrocarbon C.sub.3
Olefin/C.sub.3 Saturated 3.3 2.6 4.3 3.6 4.7 4.2 Hydrocarbon
C.sub.4 Olefin/C.sub.4 Saturated 1.6 1.6 2.0 1.8 2.3 2.5
Hydrocarbon % of i-C.sub.4/Total C.sub.4 23.9 28.4 21.9 26.6 22.4
20.6 % of Olefins/Total 68.0 65.1 71.5 69.6 69.0 72.6 Gases %
Olefins/% 2.6 2.2 3.2 2.8 3.7 3.6 Saturated Hydrocarbons
[0148] Detailed hydrocarbon analysis (DHA) of liquid products below
240.degree. C. is in the table below:
TABLE-US-00016 Hydro- Hydro- Hydro- pyrolysis 1 Pyrolysis 1
pyrolysis 2 Pyrolysis 2 pyrolysis 3 Pyrolysis 3 Paraffins, wt %
1.184 1.435 1.207 1.170 1.108 1.420 i-Paraffins, wt % 10.161 12.389
9.598 12.120 8.545 13.330 Olefins, wt % 2.944 9.159 2.555 4.858
0.976 3.900 Naphthenes, wt % 3.727 5.390 3.135 3.867 2.329 4.030
Aromatics, wt % 73.968 69.233 78.758 75.037 83.315 74.720 BTX + EX
content in 54.32 51.17 58.67 53.35 62.52 52.81 liquid boiling below
240.degree. C.
Example 12
[0149] Example 12 shows a low severity pyrolysis operation. The
experimental set up consisted of a stainless steel reactor pot
followed by a fixed bed (tubular) reactor packed with ZSM-5 zeolite
extrudates and the outlet of this tubular reactor was connected to
a stainless steel condenser/receiver tank. The reactor pot was
heated using heating tapes with temperature controller. An amount
of 100 g of mixed plastic as per composition provided in Example 10
was charged along with ZSM-5 zeolite catalyst powder of 75 microns
average particle size into the reactor and the heating was started.
The reactor temperature was maintained constant at 450.degree. C.
for a period of 1 hr. The effluent from this reactor pot was
continuously passed through the hot tubular reactor packed with
ZSM-5 extrudates and maintained at 450.degree. C. The product from
the tubular reactor was sent to the receiver. The outgoing gas from
the receiver was passed through NaOH scrubber and then diluted with
N.sub.2 and vented out through a carbon bed. Two different catalyst
loadings were tested as below: [0150] a. Experiment 1: Equivalent
to 5 wt % of the feed was the catalyst charged in the tubular
reactor and 5 wt % equivalent catalyst was charged in the reactor
pot (i.e. 10 wt % of catalyst overall). [0151] b. Experiment 2:
Equivalent to 5 wt % of the feed was the catalyst charged in the
tubular reactor and 15 wt % equivalent catalyst was charged in the
reactor pot (i.e. 20 wt % catalyst overall).
[0152] FIG. 2 shows the boiling point distribution of the liquid
product obtained indicated that 95 wt % of the liquid product
boiled below 370.degree. C.
[0153] The DHA analysis of the liquid product boiling below
240.degree. C. indicated significant presence of olefins and
aromatics:
TABLE-US-00017 Liquid Product boiling Liquid Product boiling
Product below 240.degree. C. from below 240.degree. C. from
Composition Experiment 1, wt % Experiment 2, wt % Paraffins 6.5 3.1
i-Paraffins 17.6 11.7 Olefins 11.4 7.4 Naphthenes 3.8 2.5 Aromatics
47.9 66.3 Heavies 3.1 3.6 Unknown 9.8 5.5
Example 13
[0154] Example 13 demonstrates a low severity pyrolysis with PVC
present in the feed. An amount of 100 g of mixed plastic feed as
per the composition provided in Example 10 above was mixed with 2
wt % of ZSM-5 zeolite catalyst powder and heated in a round bottom
flask fitted with a condenser. The round bottom flask was
maintained at 360.degree. C. for 1 hour. The liquid product had 60
ppmw chlorides. A similar experiment conducted with head space
purging of the round bottom flask with N.sub.2 gas provided a
liquid product with no detectable chloride content. Chloride
content in the liquid products was determined by fusing liquid
products in NaOH followed by extraction in water and measurement of
the resultant aqueous solution chloride content using ion
chromatography. This example also demonstrates the possibility of
head space purging in a pyrolysis unit to enhance
dechlorination.
Example 14
[0155] Example 14 demonstrates a low severity pyrolysis process in
a fluidized bed. An amount of 1.5 g of mixed plastic feed as per
composition provided in Example 10 was mixed with 9.05 g of a
catalyst mixture containing 62.5 wt % of FCC spent catalyst and
37.5 wt % of ZSM-5 Zeolite catalyst. This combined mixture was
charged into the fluidized bed reactor described in Example 10.
Before charging of feed and catalyst mixture the reactor was at a
temperature of 450.degree. C. The reactor temperature decreased as
the feed was charged and later increased to the set point of
450.degree. C. Data provided below also captures the temperature
profile in the reactor bed as a function of time. The 1 min, 6 min,
and 10 min average bed temperatures were 333.degree. C.,
369.degree. C., and 395.degree. C., respectively. The 1 min average
represents the average reaction temperature severity when most
temperature changes occur in the reactor. The 6 min average
represents the temperature severity when the reactor temperature
has recovered and reached the previously set value. Most of the
conversion in the low severity case was expected to have been
completed at the 6 min average. The data below shows that the
liquid product is highly aromatic, the heavier than 370.degree. C.
boiling material is only about 2 wt %, and more than 90 wt % of the
liquid product boils below 350.degree. C.
[0156] The product yield data is shown in the table below:
TABLE-US-00018 Amount, wt % H.sub.2 0.03 Methane 0.00 Ethane 0.00
Ethylene 2.25 Carbon Dioxide 1.54 Propane 3.39 Propylene 6.92
i-Butane 6.48 n-Butane 1.67 t-2-Butene 1.71 1-Butene 1.04
i-Butylene 3.37 c-2-Butene 1.26 Carbon Monoxide 0.00 Gasoline 45.28
Diesel 17.64 Heavies 2.08 Coke 5.33
[0157] The boiling point distribution is in the table below:
TABLE-US-00019 Mass Boiling Point, % .degree. C. 0.0 108.6 5.0
156.0 10.0 164.0 15.0 175.6 20.0 180.0 25.0 187.6 30.0 190.2 35.0
198.8 40.0 203.6 45.0 209.2 50.0 220.2 55.0 227.0 60.0 232.0 65.0
246.0 70.0 254.2 75.0 267.4 80.0 281.8 85.0 300.6 90.0 332.0 95.0
371.6 99.0 431.2 100.0 454.2
[0158] The detailed analysis of the liquid product is shown in the
table below:\
TABLE-US-00020 n-Paraffins, i-Paraffins, Olefins, Naphthenes,
Aromatics, Total, Carbon No. wt % wt % wt % wt % wt % wt % 3 0.003
0.003 4 0.007 0.012 0.041 0.06 5 0.032 0.077 0.325 0.095 0.529 6
0.173 0.566 1.025 1.009 4.757 7.53 7 0.379 1.379 1.547 2.095 19.393
24.793 8 0.398 2.443 0.198 1.518 28.466 33.023 9 0.046 1.911 0.134
0.958 11.254 14.303 10 0.019 0.916 0.02 0.156 4.448 5.559 11 0.022
2.114 0.029 1.621 3.786 12 0.029 0.199 0.057 3.884 4.169 13 0.078
0.111 0.189 Unknown 2.842 Heavies 3.214 Total, wt % 1.105 9.695
3.404 5.917 78.823 93.944 Total, wt % 5.49 48.18 16.92 29.41 on
Aromatics- Free Basis
Example 15
[0159] Example 15 demonstrates how a steam cracker is used in
combination with pyrolysis and hydroprocessing unit. Gases
(C.sub.1-C.sub.4) from a pyrolysis unit and hydroprocessing
facility are fed to gas crackers. Liquids from the hydroprocessing
facility are fed to liquid steam crackers.
[0160] Gas steam cracking of a feed consisting of 16.75 w % ethane,
34.62 wt % propane, 27.62 wt % isobutene and 21 wt % butane,
carried out at a steam cracker coil outlet temperature of
840.degree. C., a steam/hydrocarbon ratio of 0.35, and a coil
outlet pressure of 1.7 bar, resulted in a product having 0.48 wt %
acetylene, 34.1 wt % ethylene, 12.21 wt % propylene, and 2.41 wt %
butadiene, among other products.
[0161] Steam cracking a naphtha feed (boiling cut from initial
boiling point to 220.degree. C.) having 20.3 wt % paraffin, 27.9 wt
% i-paraffins, 14.5 wt % aromatics, and 36.9 wt % naphthenes at a
coil outlet temperature of 865.degree. C., a coil outlet pressure
of 1.7 bar, and a steam to oil ratio of 0.5 resulted in a product
having 25.86 wt % ethylene, 12.14 wt % propylene, and 4.98 wt %
butadiene.
[0162] Steam cracking of gas oils (>220.degree. C. boiling point
to 380.degree. C.) resulted in a product having 24 wt % ethylene,
14.45 wt % propylene, 4.7 wt % butadiene, and 4.5 wt % butenes.
Example 16
[0163] Example 16 demonstrates a process for sulphiding a
hydroprocessing catalyst. The particular steps of the process are
shown in FIG. 3. The time of 0 hours (zero time) in FIG. 3
corresponds to a time after the hydroprocessing catalyst is
introduced into the hydroprocessing reactor.
[0164] At ambient temperature, the hydroprocessing reactor (having
previously been loaded with the hydroprocessing catalyst) was
purged with hydrogen for 30 to 60 minutes at a set operating
pressure (e.g., 40 to 60 barg). The set operating pressure was
maintained by venting the reactor when the pressure of the reactor
during hydrogen purging increased above the set operating pressure
(e.g., due to a hydrogen source pressure greater than the set
operating pressure).
[0165] After purging the hydroprocessing reactor for 30 to 60
minutes at ambient temperature, the hydrogen purge was stopped.
[0166] Still at the ambient temperature, the sulphiding feed was
then introduced into the reactor using a high pressure pump against
the set reactor pressure at a weight hourly space velocity (WHSV)
of 3 hr.sup.-1 (on bone-dry catalyst basis). The sulphiding feed
(e.g., for use in spiking stream 14 of FIG. 1) was prepared by
mixing n-hexadecane with dimethyl disulphide in appropriate
quantity to give 3 wt % sulphur based on total weight of the
sulphiding feed. For the sulphiding feed, as per catalyst
sulphiding protocol followed, cracked feedstock cannot be used.
Hence, n-hexadecane is used. In place of n-hexadecane, straight-run
naphtha, diesel, or vacuum gas oils can also be used.
[0167] FIG. 3 indicates the hydroprocessing catalyst was soaked
with a sulphiding feed without a flow of hydrogen in the reactor
and at ambient temperature for a period of 3 hours (ending at time
3.5 hours after zero time in FIG. 3). Catalyst soaking provides for
complete wetting of the hydroprocessing catalyst; however, soaking
is optional. Liquid was drained from the bottom of a downstream gas
liquid separator.
[0168] After introducing the sulphiding feed to the reactor, the
hydroprocessing reactor bed temperature was raised to 250.degree.
C. at a rate of 30.degree. C. per hour with a flow of H.sub.2 at a
ratio of 200NL H.sub.2/L liquid feed. As shown in FIG. 3, the
temperature was increased from a time of 3.5 hours to a time of
10.8 hours after zero time.
[0169] The hydroprocessing reactor bed temperature was then held at
250.degree. C. for a period of 8 hours. As shown in FIG. 3, the
temperature was held from a time of 10.8 hours to a time of 18.8
hours after zero time.
[0170] After holding the bed temperature, the bed temperature was
further increased to 320.degree. C. to 350.degree. C. at a rate of
20.degree. C. per hour without any temperature overshoot at the
final temperature. As shown in FIG. 3, the temperature was
increased from a time of 18.8 hours to a time of 22.3 hours after
zero time.
[0171] The hydroprocessing reactor bed temperature was then
maintained at 320.degree. C. to 350.degree. C. for a period of 8
hours. As shown in FIG. 3, the temperature was maintained at
320.degree. C. to 350.degree. C. from a time of 22.3 hours to a
time of 30.0 hours after zero time.
[0172] During the step of maintaining the temperature at
320.degree. C. to 350.degree. C. for 8 hours, after 5 hours of
maintaining the temperature at 320.degree. C. to 350.degree. C.,
gas sampling began, and a first gas sample was obtained from the
reactor effluent. A second gas sample was obtained close to 8 hours
while the bed temperature is maintained at 320.degree. C. to
350.degree. C. The first and second gas samples were analyzed in a
refinery gas analyzer (RGA) gas chromatograph and constancy of
H.sub.2S concentration in reactor effluent gases in the first and
second samples signified further uptake of sulphur on the catalyst
did not take place. This marked the completion of the catalyst
sulphiding process. If the first and second samples had not
exhibited constancy in H.sub.2S concentration, additional samples
would have been taken and the temperature maintained until two
successive samples exhibited constancy in H.sub.2S
concentration.
* * * * *