Note: Descriptions are shown in the official language in which they were submitted.
IN __________________ IEGRATION OF HYDROGEN-RICH FUEL-GAS
PRODUCTION WITH OLEFINS PRODUCTION PLANT
FIELD
[0001] This disclosure relates to processes and systems for producing Hz-rich
fuel gas from
hydrocarbons such as natural gas, as well as processes and systems for
producing olefins.
BACKGROUND
[0002] There exist many industrial processes that require the generation
of very high
temperatures. Many of these processes achieve the required high temperatures
by the
combustion of hydrocarbon fuel-gas. A fuel-gas commonly used is natural gas,
which
.. comprises primarily methane. In the combustion of methane, approximately
5.8 tons of CO2
are generated for each 100 MBtu of heat released (lower heating value ("LHV")
basis).
[0003] One such large scale manufacturing process is the production of
light olefins (e.g.
ethylene, propylene, etc.). The predominant method of manufacturing light
olefins is via
steam-cracking, where a hydrocarbon feed is heated to very high temperatures
in the presence
of steam. The high temperatures (>2100 F) required to provide rapid heat
input to steam-
cracking furnaces (also known as pyrolysis reactors) are achieved by the
combustion of fuel-
gas. In many olefins production facilities the fuel-gas is internally
generated as a byproduct of
the cracking process, which can comprise primarily methane (e.g., 70-90 mol%)
with a
moderate hydrogen content (e.g., 10-30 mol%). A modern, world-scale olefins
plant may have
up to 10 steam-cracking furnaces, each of which may consume up to 150 MW or
512
MBtu/hour of fuel (LHV basis), and each of which has an individual flue-gas
exhaust stack.
Thus a modern olefins production facility can generate considerable quantity
of CO2 emissions
over an extended operation period.
[0004] Various techniques have been proposed to reduce the net CO2
emissions from steam
cracking furnaces and olefins plants. Capturing CO2 from the individual flue-
gas stacks using
an amine absorption and regeneration process has been proposed. This process
has been
demonstrated on the flue-gas stacks of electricity generation facilities. Once
captured from the
flue-gas stack, the CO2 can be compressed, liquefied and can be sequestered in
appropriate
geological formations (i.e., Carbon Capture and Sequestration, "CCS").
Application of this
technology to an olefins plant is extremely expensive given the potential to
have 10 (or more)
flue-gas stacks from which CO2 must be captured, the low CO2 concentration in
the flue-gas,
and the lack of available plot-space close to the steam-cracking furnaces in
existing facilities.
In particular, the large, internally insulated flue-gas ducting, with
associated fans and isolation
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Date Regue/Date Received 2022-12-12
facilities required to transfer the large flue-gas volumes from the furnaces
to the location of the
amine absorption unit greatly increases the cost of the facilities.
[0005] An alternative approach has been proposed wherein a high-hydrogen
fuel-gas stream
is generated for combustion in the steam-cracking furnaces, thus facilitating
the generation of
the high temperatures required by the process but with appreciably reduced CO2
emissions
from the furnaces.
[0006] Hydrogen generation from natural-gas is practiced on an
industrial scale via the
process of steam reforming. A steam-methane reformer passes heated natural-gas
(or another
suitable hydrocarbon), in the presence of large volumes of steam, through
tubes containing a
suitable catalyst, to produce a synthesis gas containing hydrogen, carbon-
monoxide, carbon-
dioxide and unconverted methane. The process is typically practiced at
pressures in the range
of 300 ¨400 psig. The process requires high temperatures, so it is normal for
various waste-
heat recovery heat exchangers to be employed in the reformer effluent stream_
The waste heat
recovery exchangers typically generate high-pressure steam (¨ 600 ¨ 650 psig)
which is then
superheated in the convection section of the reformer. Also in the reformer
effluent stream,
located at appropriate temperature conditions, it is normal to employ one or
more "shift
reactors" where, over a suitable catalyst, CO reacts with steam to produce
additional hydrogen
and CO2. Following the shift reactor(s), the reformer effluent is further
cooled to condense the
contained steam, leaving a stream predominantly containing hydrogen and CO2,
but also
containing unconverted methane and CO. In most industrial facilities a
pressure-swing-
absorption ("PSA") unit is then employed to recover high purity hydrogen (99+
%) from the
effluent stream. A so-called "PSA reject" stream is also generated, composed
of CO2, CO,
unconverted methane and some hydrogen. Historically it has been normal to use
the PSA reject
stream as a portion of the fuel-requirement of the reformer.
[0007] While the steam-methane-reforming process for hydrogen production is
well
established, there remain several drawbacks to its use for large scale
production of hydrogen
rich fuel-gas for industrial applications. First, from the description above,
it is clear that the
process has a high capital cost, employing large reforming furnaces and
multiple subsequent
processing steps. Second, the combustion of fuel-gas to provide the high
temperatures required
in the reformer itself can be source of considerable amount of CO2 emissions.
Third, the PSA
reject stream must be sent to a suitable disposition. Historically the PSA
reject stream formed
part of the fuel-gas supply to the reformer, but this further adds to the CO2
emissions from the
reformer itself.
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Date Regue/Date Received 2022-12-12
[0008] The CO2 emissions from the SMR can be reduced by installing an amine
recovery
system on the flue-gas discharged from the refontier stack. This approach
further adds to the
capital cost and operating expense of the system, particularly as the reformer
stack gas is at
low (ambient) pressure. The low operating pressure translates to large gas
volumes and hence
the amine contactor required to absorb the CO2 becomes extremely large.
[0009] There is a need, therefore, for improved processes and systems for
producing Hz-rich
fuel gas and processes and systems for producing olefins. This disclosure
satisfies this and
other needs.
SUMMARY
[0010] We have found that an Hz-rich fuel gas production plant including a
syngas
production unit and an olefins production plant including a steam cracker can
be integrated in
at least one of the following areas: fuel gas supply and consumption;
hydrocarbon feed supply
and consumption; and steam supply and consumption, to achieve a surprisingly
high level of
savings in capital and operational costs and considerable improvement in
energy efficiency and
appreciable reduction in CO2 emissions, compared to operating the two plants
separately.
[0011] Thus, a first aspect of this disclosure relates to a process comprising
one or more of
the following: (I) supplying a hydrocarbon feed and a steam feed into a syngas
producing unit
comprising a reforming reactor under syngas producing conditions to produce a
reformed
stream exiting the reforming reactor, wherein the syngas producing conditions
include the
presence of a reforming catalyst, and the reformed stream comprises H2, CO,
and steam; (II)
cooling the refoimed stream by using a waste heat recovery unit ("WHRU") to
produce a
cooled refoirned stream and to generate a high-pressure steam ("HPS") stream;
(III) contacting
the cooled reformed stream with a first shifting catalyst in a first shift
reactor under a first set
of shifting conditions to produce a first shifted stream exiting the first
shift reactor, wherein the
first shifted stream has a lower CO concentration and a higher CO2
concentration than the
cooled reformed stream; (IV) cooling the first shifted stream to obtain a
cooled first shifted
stream; (V) contacting the cooled first shifted stream with a second shifting
catalyst in a second
shift reactor under a second set of shifting conditions to produce a second
shifted stream exiting
the second shift reactor, wherein the second shifted stream has a lower CO
concentration and
a higher CO2 concentration than the cooled first shifted stream; (VI) abating
steam present in
the second shifted stream to produce a crude gas mixture stream comprising CO2
and H2; (VII)
recovering at least a portion of the CO2 present in the crude gas mixture
stream to produce a
CO2 stream and a Hz-rich stream, wherein the Hz-rich stream comprises Hz at a
concentration
of at least 80 mol%, based on the total moles of molecules in the Hz-rich
stream; and (VIII)
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Date Regue/Date Received 2022-12-12
supplying a portion of the Hz-rich stream to an olefins production plant
comprising a steam
cracker as at least a portion of a steam cracker fuel gas, and combusting the
steam cracker fuel
gas to provide thermal energy to the steam cracker.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] FIG. 1 schematically illustrates a steam supply/consumption system of a
conventional
olefins production plant including one or more steam cracker furnaces.
[0013] FIG. 2 schematically illustrates a comparative H2 production
process/plant including
an SMR.
[0014] FIG. 3 schematically illustrates a comparative process including the
comparative H2
.. production plant of FIG. 2 supplying Hz fuel gas to an olefins production
plant.
[0015] FIG. 4 schematically illustrates an exemplary Hz-rich fuel gas
production
process/plant of this disclosure.
[0016] FIG. 5 schematically illustrates an inventive process/system of this
disclosure
integrating a Hz-rich fuel gas production process/plant with an olefins
production plant.
.. [0017] FIG. 6 schematically illustrates a steam supply/consumption
configuration of a
comparative olefins production plant including multiple steam crackers.
[0018] FIG. 7 schematically illustrates an inventive steam supply/consumption
configuration
of an olefins production plant modified from the plant of FIG. 6 and steam-
integrated with an
SMR.
DETAILED DESCRIPTION
[0019] Various specific embodiments, versions and examples of the
invention will now be
described, including preferred embodiments and definitions that are adopted
herein for
purposes of understanding the claimed invention. While the following detailed
description
gives specific preferred embodiments, those skilled in the art will appreciate
that these
embodiments are exemplary only, and that the invention may be practiced in
other ways. For
purposes of determining infringement, the scope of the invention will refer to
any one or more
of the appended claims, including their equivalents, and elements or
limitations that are
equivalent to those that are recited. Any reference to the "invention" may
refer to one or more,
but not necessarily all, of the inventions defined by the claims.
[0020] In this disclosure, a process is described as comprising at least
one "step." It should
be understood that each step is an action or operation that may be carried out
once or multiple
times in the process, in a continuous or discontinuous fashion. Unless
specified to the contrary
or the context clearly indicates otherwise, multiple steps in a process may be
conducted
sequentially in the order as they are listed, with or without overlapping with
one or more other
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Date Regue/Date Received 2022-12-12
steps, or in any other order, as the case may be. In addition, one or more or
even all steps may
be conducted simultaneously with regard to the same or different batch of
material. For
example, in a continuous process, while a first step in a process is being
conducted with respect
to a raw material just fed into the beginning of the process, a second step
may be carried out
simultaneously with respect to an intermediate material resulting from
treating the raw
materials fed into the process at an earlier time in the first step.
Preferably, the steps are
conducted in the order described.
[0021] Unless otherwise indicated, all numbers indicating quantities in
this disclosure are
to be understood as being modified by the term "about" in all instances. It
should also be
understood that the precise numerical values used in the specification and
claims constitute
specific embodiments. Efforts have been made to ensure the accuracy of the
data in the
examples. However, it should be understood that any measured data inherently
contains a
certain level of error due to the limitation of the technique and/or equipment
used for acquiring
the measurement.
[0022] Certain embodiments and features are described herein using a set of
numerical
upper limits and a set of numerical lower limits. It should be appreciated
that ranges including
the combination of any two values, e.g., the combination of any lower value
with any upper
value, the combination of any two lower values, and/or the combination of any
two upper
values are contemplated unless otherwise indicated.
[0023] The indefinite article "a" or "an", as used herein, means "at least
one" unless
specified to the contrary or the context clearly indicates otherwise. Thus,
embodiments using
"a reactor" or "a conversion zone" include embodiments where one, two or more
reactors or
conversion zones are used, unless specified to the contrary or the context
clearly indicates that
only one reactor or conversion zone is used.
.. [0024] The term "hydrocarbon" means (i) any compound consisting of hydrogen
and carbon
atoms or (ii) any mixture of two or more such compounds in (i). The term "Cn
hydrocarbon,"
where n is a positive integer, means (i) any hydrocarbon compound comprising
carbon atom(s)
in its molecule at the total number of n, or (ii) any mixture of two or more
such hydrocarbon
compounds in (i). Thus, a C2 hydrocarbon can be ethane, ethylene, acetylene,
or mixtures of
at least two of these compounds at any proportion. A "Cm to Cn hydrocarbon" or
"Cm-Cn
hydrocarbon," where m and n are positive integers and m < n, means any of Cm,
Cm+1, Cm+2,
Cn-1, Cn hydrocarbons, or any mixtures of two or more thereof. Thus, a "C2 to
C3
hydrocarbon" or "C2-C3 hydrocarbon" can be any of ethane, ethylene, acetylene,
propane,
propene, propyne, propadiene, cyclopropane, and any mixtures of two or more
thereof at any
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Date Regue/Date Received 2022-12-12
proportion between and among the components. A "saturated C2-C3 hydrocarbon"
can be
ethane, propane, cyclopropane, or any mixture thereof of two or more thereof
at any proportion.
A "Cn+ hydrocarbon" means (i) any hydrocarbon compound comprising carbon
atom(s) in its
molecule at the total number of at least n, or (ii) any mixture of two or more
such hydrocarbon
compounds in (i). A "Cn- hydrocarbon" means (i) any hydrocarbon compound
comprising
carbon atoms in its molecule at the total number of at most n, or (ii) any
mixture of two or more
such hydrocarbon compounds in (i). A "Cm hydrocarbon stream" means a
hydrocarbon stream
consisting essentially of Cm hydrocarbon(s). A "Cm-Cn hydrocarbon stream"
means a
hydrocarbon stream consisting essentially of Cm-Cn hydrocarbon(s).
[0025] For the purposes of this disclosure, the nomenclature of elements is
pursuant to the
version of the Periodic Table of Elements (under the new notation) as provided
in Hawley's
Condensed Chemical Dictionary, 16th Ed., John Wiley & Sons, Inc., (2016),
Appendix V.
[0026] "Consisting essentially of' means comprising > 60 mol%, preferably > 75
mol%,
preferably > 80 mol%, preferably > 90 mol%, preferably > 95 mol%; preferably
98 mol%, of
a given material or compound, in a stream or mixture, based on the total moles
of molecules in
the stream or mixture.
[0027] "High-pressure steam" and "HPS" are used interchangeably to mean
a steam having
an absolute pressure of at least 4000 kilopascal ("kPa"). "Super-high-pressure
steam" and
"Super-HPS" are used interchangeably to mean a steam having an absolute
pressure of at least
8,370 kPa. Thus, a Super-HPS is an HPS. "Medium-pressure steam" and "MPS" are
used
interchangeably to mean a steam having an absolute pressure of at least 800
kPa but less than
4,000 kPa. "Low-pressure steam" and "LPS" are used interchangeably to mean a
steam having
an absolute pressure of at least 200 kPa but less than 800 kPa.
[0028] A "back-pressure steam turbine" means a steam turbine receiving a
steam feed and
.. producing no steam stream having an absolute pressure below 100 kPa and
supplied to a surface
condenser. Depending on the pressure of the steam feed and its configuration,
a back-pressure
steam turbine may produce one or more exhaust streams, e.g., an HPS stream, an
MPS stream,
and LPS stream, and combinations thereof. In this disclosure, unless the
context clearly
indicates otherwise, a turbine is a steam turbine.
[0029] An "extraction steam turbine" means a steam turbine receiving a steam
feed and
producing at least two exhaust steam streams having differing pressures.
Depending on the
pressure of the steam feed and its configuration, an extraction steam turbine
may produce two
or more steam streams including one or more of, e.g., an HPS stream, an MPS
stream, an LPS
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Date Regue/Date Received 2022-12-12
stream, and an condensable stream having an absolute pressure below 100 kPa
supplied to a
surface condenser.
I. The Process and Plant for Producing a H2-Rich Fuel Gas
[0030] One aspect of this disclosure is directed to a process for producing Hz-
rich fuel gas
comprising the following steps: (I) supplying a hydrocarbon feed and a steam
feed into a syngas
producing unit comprising a reforming reactor under syngas producing
conditions to produce
a reformed stream exiting the reforming reactor, wherein the syngas producing
conditions
include the presence of a refoiming catalyst, and the reformed stream
comprises 112, CO, and
steam; (II) cooling the reformed stream by using a waste heat recovery unit
("WHRU") to
produce a cooled reformed stream and to generate a high-pressure steam ("HPS")
stream; (III)
contacting the cooled reformed stream with a first shifting catalyst in a
first shift reactor under
a first set of shifting conditions to produce a first shifted stream exiting
the first shift reactor,
wherein the first shifted stream has a lower CO concentration and a higher CO2
concentration
than the cooled reformed stream; (IV) cooling the first shifted stream to
obtain a cooled first
shifted stream; (V) contacting the cooled first shifted stream with a second
shifting catalyst in
a second shift reactor under a second set of shifting conditions to produce a
second shifted
stream exiting the second shift reactor, wherein the second shifted stream has
a lower CO
concentration and a higher CO2 concentration than the cooled first shifted
stream; (VI) abating
steam present in the second shifted stream to produce a crude gas mixture
stream comprising
CO2 and H2; and (VII) recovering at least a portion of the CO2 present in the
crude gas mixture
stream to produce a CO2 stream and a Hz-rich stream, wherein the Hz-rich
stream comprises
H2 at a concentration of at least 80 mol%, based on the total moles of
molecules in the Hz-rich
stream. A system for producing such an Hz-rich stream, preferably using the
above process,
may be called an Hz-rich fuel gas production plant in this disclosure.
[0031] Step (I) of this process includes supplying a hydrocarbon feed and a
steam feed into
a syngas producing unit comprising a reforming reactor under syngas producing
conditions to
produce a reformed stream exiting the reforming reactor, wherein the syngas
producing
conditions include the presence of a reforming catalyst, and the reformed
stream comprises Hz,
CO, and steam. The hydrocarbon feed can consist essentially of C1-C4
hydrocarbons
(preferably saturated), preferably consists essentially of Cl-C3 hydrocarbons
(preferably
saturated), preferably consists essentially of C 1-C2 hydrocarbons (preferably
saturated), and
preferably consists essentially of CH4. The hydrocarbon feed and the steam
feed may be
combined to form a joint stream before being fed into the syngas producing
unit. Alternatively,
they may be fed into the syngas producing unit as separate streams, in which
they admix with
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Date Regue/Date Received 2022-12-12
each other to form a mixture. The feed stream(s) can be pre-heated by, e.g., a
furnace, a heat
exchanger, and the like, before being fed into the syngas producing unit. The
syngas producing
unit can comprise a pre-reformer first receiving the feed stream(s),
especially if the
hydrocarbon feed comprises significant amount of C2+ hydrocarbons. In a pre-
reformer, the
hydrocarbon feed/steam feed mixture contacts a pre-reforming catalyst under
conditions such
that the C2+ hydrocarbons are preferentially converted into CH4. The inclusion
of a pre-
reformer can reduce coking and fouling of the down-stream reforming reactor.
The
hydrocarbon feed may have a temperature from, e.g., 15 C, 20 C, 30 C, 40
C, to 50 C,
60 C, 70 C, 80 C, 90 C, to 95 C, 100 C, 110 C, 120 C, 130 C, 140 Cõ or
even 150 C,
and an absolute pressure from e.g., 1,300 kPa, 1,400 kPa, 1,500 kPa, 1,600
kPa, 1,700 kPa,
1,800 kPa, 1,900 Oa, 2,000 kPa, to 2,100 kPa, 2,200 kPa, 2,300 kPa, 2,400 kPa,
2,500 kPa,
2,600 kPa, 2,700 kPa, 2,800 kPa, 2,900 kPa, 3,000 kPa, to 3,000 kPa, 3,200
kPa, 3,400 kPa,
3,500 kPa, 3,600 kPa, 3,800 kPa, 4,000 kPa, to 4,200 kPa, 4,400 kPa, 4,500
kPa, 4,600 kPa,
4,800 kPa, or even 5,000 kPa. The steam feed may have a temperature from,
e.g., 250 C,
260 C, 270 C, 280 C, 290 C, 300 C, to 310 C, 320 C, 330 C, 340 C, 350
C, 360 C,
370 C, 380 C, 390 C, to 400 C, 410 C, 420 C, 430 C, 440 C, or even 450
C, and an
absolute pressure from e.g., 1,300 kPa, 1,400 kPa, 1,500 kPa, 1,600 kPa, 1,700
kPa, 1,800 kPa,
1,900 kPa, 2,000 kPa, to 2,100 kPa, 2,200 kPa, 2,300 kPa, 2,400 kPa, 2,500
kPa, 2,600 kPa,
2,700 kPa, 2,800 kPa, 2,900 kPa, 3,000 kPa, to 3,000 kPa, 3,200 kPa, 3,400
kPa, 3,500 kPa,
.. 3,600 kPa, 3,800 kPa, 4,000 kPa, to 4,200 kPa, 4,400 kPa, 4,500 kPa, 4,600
kPa, 4,800 kPa, or
even 5,000 kPa. Preferably, the steam feed is a superheated steam.
[0032] The effluent from the pre-reformer can be then fed into the
reforming reactor
operated under syngas producing conditions, wherein the forward reaction of
the following is
favored and desirably occurs in the presence of the reforming catalyst:
Reforming Catalyst
+ H20 - C0+3H2
(R-1)
[0033] The syngas producing condition can include a temperature of,
e.g., from 750 C, 760
C, 780 C, 800 C, 850 C, 900 C, to 950 C, 1,000 C, 1,050 C, 1,100 C, to
1150 C, or
even 1200 C, and an absolute pressure of, e.g., from 700 kPa, 800 kPa, 900
kPa, 1,000 kPa,
to 1,500 kPa, 2,000 kPa, 2,500 kPa, 3,000 kPa, to 3,500 kPa, 4,000 kPa, 4,500
kPa, or even
5,000 kPa, in the reforming reactor, depending on the type of the reforming
reactor and the
syngas producing conditions. A lower pressure in the refoinied stream, and
hence a lower
pressure in the reforming reactor, is conducive to a higher conversion of CH4
in reforming
reactor and hence a lower residual CH4 concentration in the reformed stream.
The reformed
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Date Regue/Date Received 2022-12-12
stream exiting the reforming reactor therefore comprises CO, H2, residual CH4
and H20, and
optionally CO2 at various concentrations depending on, among others, the type
of the reforming
reactor and the syngas producing conditions. The reformed stream can have a
temperature of,
e.g., from 750 C, 760 C, 780 C, 800 C, 850 C, 900 C, to 950 C, 1,000
C, 1,050 C,
1,100 C, to 1150 C, or even 1200 C, and an absolute pressure of, e.g., from
700 kPa, 800
kPa, 900 kPa, 1,000 kPa, to 1,500 kPa, 2,000 kPa, 2,500 kPa, 3,000 kPa, to
3,500 kPa, 4,000
kPa, 4,500 kPa, or even 5,000 kPa, depending on the type of the refolining
reactor and the
syngas producing conditions.
[0034] A preferred type of the reforming reactor in the syngas producing
unit is an SMR.
An SMR typically comprises one or more heated reforming tubes containing the
reforming
catalyst inside. The hydrocarbon/steam feed stream enters the tubes, heated to
a desired
elevated temperature, and passes through the reforming catalyst to effect the
desirable
reforming reaction mentioned above. While an SMR can have many different
designs, a
preferred SMR comprises a furnace enclosure, a convection section (e.g., an
upper convection
section), a radiant section (e.g., a lower radiant section), and one or more
burners located in the
radiant section combusting a fuel to produce a hot flue gas and supply thermal
energy to heat
the radiant section and the convection section. The hydrocarbon/steam feed
stream enters the
reforming tube at a location in the convection section, winds downwards
through the
convection section, whereby it is pre-heated by the ascending hot flue gas
produced from fuel
combustion at the burner(s), and then enters the radiant section proximate the
burners
combustion flames, whereby it contacts the reforming catalyst loaded in the
reforming tube(s)
in the radiant section, to produce a refoimed stream exiting the SMR from a
location in the
radiant section. The syngas producing conditions in the reforming tube(s) in
the radiant section
can include a temperature of, e.g., from 750 C, 760 C, 780 C, 800 C, to
820 C, 840 C,
850 C, to 860 C, 880 C, or even 900 C, and an absolute pressure of, e.g.,
from 700 kPa, 800
kPa, 800 kPa, 900 kPa, 1,000 kPa, to 1,500 kPa, 2,000 kPa, 2,500 kPa, 3,000
kPa, or even
3,500 kPa. To achieve a high CH4 conversion in the SMR, and a low CH4
concentration in the
H2-rich stream produced from the process, the syngas producing conditions in
the SMR
preferably includes an absolute pressure of < 2,169 kPa (300 psig), more
preferably < 1,825
kPa (250 psig). Description of an SMR can be found in, e.g., The International
Energy Agency
Greenhouse Gas R&D Program ("IEAGHG"), "Techno-Economic Evaluation of SMR
Based
Standalone (Merchant) Plant with CCS", February 2017; and IEAGHG, "Reference
data and
supporting literature Reviews for SMR based Hydrogen production with CCS",
2017-TR3,
March 2017.
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Date Regue/Date Received 2022-12-12
[0035] The reforming reactor in the syngas producing unit may comprise
an autothermal
refoluter ("ATR"). An ATR typically receives the hydrocarbon/steam feed(s) and
an 02 stream
into a reaction vessel, where a portion of the hydrocarbon combusts to produce
thermal energy,
whereby the mixture is heated to an elevated temperature and then allowed to
contact a bed of
reforming catalyst to effect the desirable reforming reaction and produce a
reformed stream
exiting the vessel. An ATR can be operated at a higher temperature and
pressure than an SMR.
The syngas producing conditions in the ATR and the reformed stream exiting an
ATR can have
a temperature of, e.g., from 800 C, 850 C, 900 C, to 950 C, 1,000 C, 1050
C, to 1,100 C,
1,150 C, or even 1,200 C, and an absolute pressure of, e.g., from 800 kPa,
900 kPa, 1,000
kPa, to 1,500 kPa, 2,000 kPa, 2,500 kPa, 3,000 kPa, to 3,500 kPa, 4,000 kPa,
4,500 kPa, or
even 5,000 kPa. Commercially available ATRs, such as the Syncorrm ATR
available from
Haldor Topsoe, having an address at Haldor Topsoes Alle 1, DK-2800, Kgs.
Lyngby, Denmark
("Topsoe"), may be used in the process of this disclosure.
[0036] The syngas producing unit used in step (I) of the process of this
disclosure can
include one or more SMR only, one or more ATR only, or a combination of one or
more of
both.
[0037] The reformed stream exiting the reforming reactor has a high
temperature and high
pressure as indicated above. It is highly desirable to capture the heat energy
contained therein.
Thus, in step (II), the reformed stream passes through a waste heat recovery
unit ("WHRU")
to produce a cooled reformed stream and to generate a high-pressure steam
("HPS") stream.
The cooled refoimed stream can have a temperature from, e.g., 285 C, 290 C,
300 C, to 310
C, 320 C, 330 C, 340 C, 350 C, to 360 C, 370 C, 380 C, 390 C, or even
400 C. The
cooled reformed stream can have a pressure substantially the same as the
reformed stream
exiting the reforming reactor. The WHRU can include, e.g., one or more heat
exchanger and
one or more steam drum in fluid communication with the heat exchanger. The
steam drum
supplies a water stream to the heat exchanger, where it is heated and a
water/steam stream can
be then returned to the steam drum, where steam is separated from liquid phase
water. The HPS
stream can have an absolute pressure from, e.g., 4,000 kPa, 5,000 kPa, 6,000
kPa, 7,000 kPa,
8,000 kPa, to 9,000 kPa, 10,000 kPa, 11,000 kPa, 12,000 kPa, 13,000 kPa, or
even 14,000 kPa.
The thus produced HPS stream is a saturated steam stream. To make the HPS
stream more
useful, it may be further heated to produce a superheated HPS ("SH-HPS")
stream in, e.g., a
furnace. In case the syngas producing unit comprises an SMR having a
convection section as
described above, the saturated HPS stream may be advantageously superheated in
the
convection section of the SMR and/or in an auxiliary furnace. In case the
syngas producing
Date Regue/Date Received 2022-12-12
unit comprises one or more ATR but no SMR, the saturated HPS stream can be
superheated in
an auxiliary furnace. The auxiliary furnace can include one or more burners
combusting a fuel
gas stream to supply the needed thermal energy as is known to one skilled in
the art. The SH-
HPS stream can have one of both of: (i) a temperature from, e.g., 350 C, 360
C, 370 C, 380
C, 390 C, 400 C, to 410 C, 420 C, 430 C, 440 C, 450 C, to 460 C, 470
C, 480 C,
490 C, 500 C, to 510 C, 520 C, 530 C, 540 C, or even 550 C; and (ii) an
absolute pressure
from, e.g., e.g., 4,000 kPa, 5,000 kPa, 6,000 kPa, 7,000 kPa, 8,000 kPa, to
9,000 kPa, 10,000
kPa, 11,000 kPa, 12,000 kPa, 13,000 kPa, or even 14,000 kPa.
[0038] In step (III) of the process of this disclosure, the cooled
reformed stream contacts a
first shifting catalyst in a first shift reactor under a first set of shifting
conditions to produce a
first shifted stream exiting the first shift reactor. The first set of
shifting conditions includes the
presence of a first shift catalyst. Any suitable shift catalyst known to one
skilled in the art may
be used. Non-limiting examples of suitable shift catalyst for the first
shifting catalyst are high
temperature shift catalysts available from, e.g., Topsoe. The forward reaction
of the following
preferentially occur in the first shift reactor:
First Shift Catalyst
CO + H2O - CO2 + H2
(R-2)
[0039] As such, the first shifted stream has a lower CO concentration
and a higher CO2
concentration than the cooled reformed stream. The forward reaction of (R-2)
is exothermic,
resulting in the first shifted stream having a temperature higher than the
cooled reformed stream
entering the first shift reactor. The first shifted stream exiting the first
shift reactor can have a
temperature from, e.g., 335 C, 340 C, 350 C, 360 C, to 370 C, 380 C, 400
C, 420 C, to
440 C, 450 C, 460 C, 480 C, or even 500 C. The first shifted stream can
have an absolute
pressure substantially the same as the cooled refonned stream.
[0040] While a single stage of shift reactor may convert sufficient
amount of CO in the
cooled reformed stream to CO2 resulting in a low CO concentration in the first
shifted stream,
it is preferable to include at least two stages of shift reactors in the
processes of this disclosure
to achieve a high level of conversion of CO to CO2, and eventually to produce
a H2-rich fuel
gas stream with low CO concentration. It is further preferred that a
subsequent stage, such as
the second shift reactor downstream of the first shift reactor is operated at
a temperature lower
than the first shift reactor, whereby additional amount of CO in the first
shifted stream is further
converted into CO2 and additional amount of H2 is produced. To that end, the
first shifted
stream is preferably first cooled down in step (IV) to produce a cooled first
shifted stream.
Such cooling can be effected by one or more heat exchangers using one or more
cooling streams
11
Date Regue/Date Received 2022-12-12
having a temperature lower than the first shifted stream. In one preferred
embodiment, the first
shifted stream can be cooled by the hydrocarbon stream or a split stream
thereof to be fed into
the syngas producing unit. Alternatively or additionally, the first shifted
stream can be cooled
by a boiler water feed stream to produce a heated boiler water stream, a steam
stream, and/or a
water/steam mixture stream. The thus heated boiler water stream can be heated
in a boiler to
produce steam at various pressure. The thus heated boiler water stream, steam
stream, and/or
water/steam mixture stream can be further heated by another process stream in
another heat
exchanger to produce steam. In one preferred embodiment, the heated boiler
water stream
and/or steam stream can be fed into the steam drum of the WHRU extracting heat
from the
reformed stream as described above, where the boiler feedwater can be sent to
the WHRU
exchanger for further heating, and any steam separated in the steam drum can
be further
superheated. The cooled first shifted stream can have a temperature from,
e.g., 150 C, 160 C,
170 C, 180 C, 190 C, 200 C, to 210 C, 220 C, 230 C, 240 C, or even 250
C, and a
pressure substantially the same as the first shifted stream.
[0041] The cooled first shifted stream is then subjected to a low-
temperature shifting in a
second shift reactor under a second set of shifting conditions to produce a
second shifted
stream. The second set of shifting conditions includes the presence of a
second shift catalyst,
which may be the same or different from the first shift catalyst. Any suitable
shift catalyst
known to one skilled in the art may be used. Non-limiting examples of suitable
catalyst for the
second shifting catalyst are low temperature shift catalysts available from,
e.g., Topsoe. The
forward reaction of the following preferentially occur in the second shift
reactor:
Second Shift Catalyst
CO + H20 -. CO2 + H2
(R-3)
[0042] As such, the second shifted stream has a lower CO concentration
and a higher CO2
concentration than the cooled first shifted stream. The forward reaction of (R-
3) is exothermic,
resulting in the second shifted stream having a temperature higher than the
cooled first shifted
stream entering the second shift reactor. The second shifted stream exiting
the second shift
reactor can have a temperature from, e.g., e.g., 150 C, 160 C, 170 C, 180
C, 190 C, 200
C, to 210 C, 220 C, 230 C, 240 C, 250 C, to 260 C, 270 C, 280 C, 290
C, or even 300
C. The second shifted stream can have an absolute pressure substantially the
same as the
cooled first shifted stream.
[0043] The second shifted stream comprises Hz, CO2, CO, steam, and
optionally CH4. In
step (VI), steam is then abated from it by cooling and separation. Similar to
step (IV) of cooling
the first shifted stream, such cooling of the second shifted stream can be
effected by one or
12
Date Regue/Date Received 2022-12-12
more heat exchangers using one or more cooling streams having a temperature
lower than the
second shifted stream_ In one preferred embodiment, the second shifted stream
can be cooled
by the hydrocarbon stream or a split stream thereof to be fed into the syngas
producing unit.
Alternatively or additionally, the second shifted stream can be cooled by a
boiler water feed
stream to produce a heated boiler water stream, a steam stream, and/or a
water/steam mixture
stream. The thus heated boiler water stream can be heated in a boiler to
produce steam at
various pressure. The thus heated boiler water stream, steam stream, and/or
water/steam
mixture stream can be further heated by another process stream in another heat
exchanger to
produce steam. In one preferred embodiment, the heated boiler water stream
and/or steam
stream can be fed into the steam drum of the WHRU extracting heat from the
reformed stream
as described above, where the boiler feedwater can be sent to the WHRU
exchanger for further
heating, and any steam separated in the steam drum can be further superheated.
Alternatively
or additionally, cooling water exchangers or air-fin heat exchangers can be
used to at least
partly cool the second shifted syngas stream. The cooled second shifted stream
can preferably
comprise water condensate, which can be separated to produce a crude gas
mixture stream
comprising steam at a significantly lower concentration than the second
shifted stream exiting
the second shift reactor.
[0044] The crude gas mixture stream thus consists essentially of CO2,
H2, optionally CH4
at various amounts, and steam and CO as minor components. The crude gas
mixture stream
can have an absolute pressure from, e.g., 700 kPa, 800 kPa, 800 kPa, 900 kPa,
1,000 kPa, to
1,500 kPa, 2,000 kPa, 2,500 kPa, 3,000 kPa, to 3,500 kPa, 4,000 kPa, 4,500
kPa, or even 5,000
kPa. In step (VII), one can recover a portion of the CO2 therein to produce a
CO2 stream and
a H2-rich stream. Any suitable CO2 recovery process known to one skilled in
the art may be
used in step (VII), including but not limited to: (i) amine absorption and
regeneration process;
(ii) a cryogenic CO2 separation process; (iii) a membrane separation process;
(iv) a physical
absorption and regeneration process; and (iv) any combination any of (i),
(ii), and (iii) above.
In a preferred embodiment, an amine absorption and regeneration process may be
used. Due to
the elevated pressure of the crude gas mixture stream, the size of the CO2
recovery equipment
can be much smaller than otherwise required to recover CO2 from a gas mixture
at atmospheric
pressure.
[0045] The CO2 stream preferably comprises CO2 at a molar concentration
of from, e.g.,
90%, 91%, 92%, 93%, 94%, to 95%, 96%, 97%, 98%, or even 99%, based on the
total moles
of molecules in the CO2 stream. The CO2 stream can comprise at least one and
preferably all
of, on a molar basis: (i) e.g., from 0.1%, 0.2%, 0.3%, 0.4%, 0.5%, 0.6%, 0.7%,
0.8%, 0.9%, to
13
Date Regue/Date Received 2022-12-12
1.0%, 1.5%, 2.0%, 2.5%, 3.0%, 3.5%, 4.5%, or even 5.0% of CO; (ii) e.g., from
0.1%, 0.2%,
0.3%, 0.4%, 0.5%, 0.6%, 0.7%, 0.8%, 0.9%, to 1.0%, 1.5%, 2.0%, 2.5%, 3.0%,
3.5%, 4.5%,
5.0%, 5.5%, or even 6.0% of H20; and (iii) e.g., from 0.1%, 0.2%, 0.3%, 0.4%,
0.5%, 0.6%,
0.7%, 0.8%, 0.9%, to 1.0%, 1.5%, 2.0%, 2.5%, 3.0%, 3.5%, 4.5%, or even 5.0% of
CH4. The
CO2 stream can have an absolute pressure from, e.g., 700 kPa, 800 kPa, 800
kPa, 900 kPa,
1,000 kPa, to 1,500 kPa, 2,000 kPa, 2,500 kPa, 3,000 kPa, to 3,500 kPa, 4,000
kPa, 4,500 kPa,
or even 5,000 kPa. The CO2 stream can be compressed, liquefied, conducted
away, stored,
sequestered, or utilized in any suitable applications known to one skilled in
the art. In one
embodiment, the CO2 stream, upon optional compression, can be conducted away
in a CO2
pipeline. In another embodiment, the CO2 stream, upon optional compression
and/or
liquefaction, can be injected and stored in a geological formation. In yet
another embodiment,
the CO2 stream, upon optional compression and/or liquefaction, can be used in
extracting
hydrocarbons present in a geological formation. Another exemplary use of the
CO2 stream is
in food applications.
[0046] The Hz-rich stream can have an absolute pressure from, e.g., 700
kPa, 800 kPa, 800
kPa, 900 kPa, 1,000 kPa, to 1,500 kPa, 2,000 kPa, 2,500 kPa, 3,000 kPa, to
3,500 kPa, 4,000
kPa, 4,500 kPa, or even 5,000 kPa. The Hz-rich stream preferably comprises Hz
at a molar
concentration of from, e.g., 80%, 81%, 82%, 83%, 84%, 85%, to 86%, 87%, 88%,
89%, 90%,
to 91%, 92%, 93%, 94%, 95%, to 96%, 97%, or even 98%, based on the total moles
of
molecules in the Hz-rich stream. The Hz-rich stream can comprise at least one
and preferably
all of, on a molar basis: (i) e.g., from 0.1%, 0.2%, 0.3%, 0.4%, 0.5%, 0.6%,
0.7%, 0.8%, 0.9%,
to 1.0%, 1.5%, 2.0%, 2.5%, or even 3.0%, of CO; (ii) e.g., from 0.1%, 0.2%,
0.3%, 0.4%, 0.5%,
to 0.6%, 0.7%, 0.8%, 0.9%, or even 1.0%, of CO2; and (iii) e.g., from 0.1%,
0.2%, 0.3%, 0.4%,
0.5%, 0.6%, 0.7%, 0.8%, 0.9%, to 1.0%, 1.5%, 2.0%, 2.5%, 3.0%, 3.5%, 4.5%, or
even 5.0%
of CH4. One specific example of a Hz-rich stream that may be produced from the
process of
this disclosure has the following molar composition: 0.25% of CO2; 1.75% of
CO; 93.87% of
Hz; 0.23% of 1\12; 3.63% of C1-14; and 0.29% of 1120.
[0047] Where an even higher purity H2 stream is desired, a portion of
the Hz-rich stream
can be further purified by using processes and technologies known to one
skilled in the art,
e.g., pressure-swing-separation.
[0048] Preferably, however, the Hz-rich stream, notwithstanding the
optional low
concentrations of CO, CO2, and CH4, is used as a fuel gas stream without
further purification
to provide heating in step (VIII) of the process in, e.g., residential,
office, and/or industrial
applications, preferably industrial applications. Due to the considerably
reduced combined
14
Date Regue/Date Received 2022-12-12
concentrations of CO, CO2, and CH4 therein compared to conventional fuel gases
such as
natural gas, the flue gas stream produced from combusting the Hz-rich stream
can comprise
CO2 at a considerably reduced concentration, resulting in appreciably lower
CO2 emission to
the atmosphere. Thus, the flue gas stream can comprise CO2 at a molar
concentration from,
e.g., 0.01%, 0.05%, to 0.1%, 0.2%, 0.3%, 0.4%, 0.5%, 0.6%, 0.7%, 0.8%, 0.9%,
to 1%, 2%,
3%, 4%, 5%, 6%, 7%, 8%, 9%, 10%, to 11%, 12%, 13%, 14%, 15%, 16%, 17%, 18%,
19%,
or 20%, preferably < 10%, preferably < 5%, preferably < 3%, based on the total
moles of CO2
and H2O in the flue gas stream. The combustion may be in the presence of,
e.g., air, 02-
enhanced air, high-purity 02, and the like, depending on the specific
application.
[0049] For use as a fuel gas stream, the Hz-rich stream may preferably have
an absolute
pressure of 5. 1,135 kPa (150 psig), preferably < 790 kPa (100 psig). To
achieve such low
pressure of the Hz-rich stream, it is feasible to design a syngas producing
unit upstream
comprising an SMR and/or an ATR operating under syngas producing conditions
including a
relatively low pressure, e.g., an absolute pressure of < 2,169 kPa (300 psig),
preferably < 1,825
kPa (250 psig). As mentioned above, a lower pressure in the reforming reactor
results in a
higher CH4 conversion in the reforming reactor, and hence a low residual CH4
concentration
in the Hz-rich stream.
[0050] Preferably, the Hz-rich stream is supplied to at least one,
preferably a majority,
preferably all, of the combustion devices used in the process/system for
producing the Hz-rich
stream. Thus, where the syngas producing unit comprises a pre-reformer
including a furnace
heated by one or more burners combusting a fuel gas, preferably a portion of
the Hz-rich stream
is supplied as at least a portion, preferably a majority, preferably the
entirety, of the fuel gas to
such burners. Where the syngas producing unit includes an SMR comprising one
or more SMR
burners combusting a SMR fuel, it is highly desirable to supply a portion of
the Hz-rich stream
as at least a portion, preferably a majority, preferably the entirety, of the
SMR fuel. Where the
Hz-rich stream production process/system uses an additional boiler or
auxiliary furnace
combusting a fuel gas, it is desirable to supply a portion of the Hz-rich
stream as at least a
portion, preferably a majority, preferably the entirety, of the fuel gas. By
combusting the H2-
rich stream and capturing the CO2 stream, the Hz-rich stream production
process/system of this
disclosure can reach an appreciably reduced level of CO2 emission to the
atmosphere than
conventional H2 production processes combusting natural gas.
[0051] Compared to existing syngas and/or Hz-rich fuel gas producing
processes, especially
those combusting a hydrocarbon-containing fuel, the Hz-rich fuel gas
production process of
this disclosure has at least one of the following advantages: (i) lower
capital investment and
Date Regue/Date Received 2022-12-12
production cost due to, e.g., an absence of a PSA unit, a small-size CO2
recovery unit, and
operating the syngas producing unit, the first shift reactor, and the second
shift gas reactor
under relatively low pressure; and (ii) considerably lower CO2 emission if the
CO2 stream is
captured, stored, sequestered, and/or utilized.
II. Integration of an H2-rich Fuel Gas Production Plant with an Olefins
Production Plant
[0052] A modem olefins production plant typically operates by feeding a
hydrocarbon feed
(e.g., ethane, propane, butanes, naphtha, crude oil, and mixtures and
combinations thereof) and
steam into a steam cracker, heating the hydrocarbon feed/steam mixture to an
elevated cracking
temperature for a desirable residence time, thereby cracking the hydrocarbon
feed to produce
a steam cracker effluent comprising H2, CH4, ethane, propane, butanes, C2-C4
olefins, C4
dienes, and C5+ hydrocarbons exiting the pyrolysis reactor. The heating can
include a
preheating step in the convection section of the steam cracker, followed by
transfer to the
radiant section, where additional heating to the elevated cracking temperature
and cracking
occur. The thermal energy need for the preheating in the convection section
and the heating in
the radiant section is typically provided by a plurality of steam cracker
burners combusting a
steam cracker fuel gas. The high-temperature steam cracker effluent is
immediately cooled
down by quenching and/or indirect heat exchange, and separated to produce,
among others, a
process gas stream comprising Cl-C4 hydrocarbons. The process gas stream is
then typically
compressed and supplied to a product recovery section including a chill train
and multiple
distillation columns such as a demethanizer, a deethanizer, a depropanizer, a
C2 splitter, a C3
splitter, to name a few, from which one of more of the following may be
produced: (i) a steam-
cracker H2 stream, which may preferably comprise H2 at a molar concentration
of from, e.g.,
80%, 81%, 82%, 83%, 84%, 85%, to 86%, 87%, 88%, 89%, 90%, to 91%, 92%, 93%,
94%,
95%, to 96%, 97%, or even 98%, based on the total moles of molecules in the
steam-cracker
H2 stream; (ii) a C114-rich stream (sometimes referred to as a "tailgas
stream") comprising CH4
at a molar concentration from, e.g., 50%, 55%, 60%, 65%, 70%, to 75%, 80%,
85%, 90%, to
91%, 92%, 93%, 94%, 95%, 96%, 97%, or even 98%, based on the total moles of
molecules in
the CH4-rich stream; (ii) an ethane stream; (iii) an ethylene product stream;
(iv) a propane
stream; and (v) a propylene product stream. Many configurations of the
recovery sections are
possible. The steam-cracker H2 stream may comprise, on a molar basis, e.g.,
from 0.1%, 0.2%,
0.3%, 0.4%, 0.5%, 0.6%, 0.7%, 0.8%, 0.9%, to 1.0%, 1.5%, 2.0%, 2.5%, 3.0%,
3.5%, 4.5%,
5.0%, to 6.0%, 8.0%, 10%, 12%, 14%, 15%, to 16%, 17%, 18%, 19%, or even 20% of
CH4.
Preferably the steam-cracker H2 stream is substantially free of CO2 and CO,
e.g., comprising
CO2 and CO at a combined concentration from 0 to no greater than 1% by mole,
based on the
16
Date Regue/Date Received 2022-12-12
total moles of molecules in the steam-cracker H2 stream. The CI-la-rich stream
may comprise
at least one and preferably all of, on a molar basis: (i) e.g., from 1%, 5%,
10%, 15%, to 20%,
25%, 30%, to 35%, or even 40%, 45% Hz; (ii) e.g., from 0.1%, 0.5%, 1%, to 2%,
3%, 4%, 5%,
to 6%, 7%, 8%, 9%, or 10% ethane; and (iii) e.g., from 0.01%, 0.05%, 0.1%, to
0.2%, 0.5%,
1%, to 2%, 3%, 4%, or 5% CO, based on the total moles of molecules in the CH4-
rich stream.
11.1 Fuel Gas Integration
[0053] The Hz-rich fuel gas production process/plant of this disclosure,
as described in
section I above, can be advantageously integrated with an olefins production
plant to achieve
an enhanced level of energy efficiency and a reduced level of CO2 emissions to
the atmosphere,
compared to previous processes/systems and operating them separately
regardless of the
specific configuration of the recovery section in the plant.
[0054] In certain preferred embodiments, a portion of the Hz-rich stream
may be combined
with a portion of the steam-cracker Hz stream to form a joint Hz-rich stream,
which can be used
as a fuel gas for residential, office, and/or industrial heating applications,
particularly industrial
heating applications such as in an olefins production plant.
[0055] In one particularly desirable embodiment, a portion of the Hz-
rich stream, the steam-
cracker Hz stream, or the joint Hz-rich stream can be supplied to one of more
of the steam
cracker burners as at least a portion, preferably a majority, preferably the
entirety, of the steam
cracker fuel gas. A steam cracker can consume large quantity of the steam
cracker fuel gas,
which hitherto tends to comprise substantial quantity of hydrocarbons such as
CHa. By
substituting a portion, preferably majority, preferably the entirety, of the
steam cracker fuel gas
with the Hz-rich stream, the steam-cracker H2 stream, and/or the joint Hz-rich
stream, each
containing low concentrations of carbon-containing species, considerable
reduction of CO2
emission from the steam cracker flue gas can be achieved. In certain
embodiments, the steam
cracker may preferably be equipped with a combustion air pre-heater to reduce
the fuel
consumption requirements of the steam cracker. The combustion air pre-heater
can preferably
provide heating by electrical heating and/or exchanging heat with a warmer
stream such as: the
flue-gas of the same or different furnace; a steam stream (preferably a low-
pressure steam
stream), a hot water stream, and/or a hot oil stream.
[0056] An olefins production plant may include one or more boilers and/or
auxiliary
furnaces combusting a fuel gas in addition to the steam cracker. In such case,
it is highly
advantageous to supply a portion of the Hz-rich stream, the steam-cracker H2
stream, and/or
the joint Hz-rich stream to such boilers and/or auxiliary furnaces as a
portion, preferably a
17
Date Regue/Date Received 2022-12-12
majority, preferably the entirety, of the fuel gas needed. Doing so can
further reduce CO2
emission to the atmosphere from the olefins production plant.
[0057] An olefins production plant may comprise a combined-cycle power
plant comprising
one or more duct burners combusting a duct burner fuel to generate thermal
energy. In such
case, it is highly advantageous to supply a portion of the Hz-rich stream, the
steam-cracker H2
stream, and/or the joint Hz-rich stream to the duct burners as a portion,
preferably a majority,
preferably the entirety, of the duct burner fuel needed.
[0058] In certain embodiments, the Hz-rich stream and/or the steam-
cracker Hz stream can
supply from, e.g., 60%, 65%, 70%, to 75%, 80%, 85%, to 90%, 95%, 98%, 99%, or
even 100%,
of the total fuel gas required, on a Btu basis, in the olefins production
plant. In certain
embodiments, the Hz-rich stream can supply from, e.g., 60%, 65%, 70%, to 75%,
80%, 85%,
to 90%, 95%, 98%, 99%, or even 100%, of the total fuel gas required, on a Btu
basis, in the
olefins production plant.
[0059] In the following TABLE I, the CO2 footprint of a steam cracker
combusting the
following fuel gases emitting flue gases produced from the combustion are
compared: (i) only
a typical natural gas ("Natural Gas"); (ii) only a tailgas produced from a
steam cracker
receiving a typical naphtha steam-cracking feed ("Tailgas"); (iii) a CO-rich
fuel gas produced
from a comparison process including a syngas producing unit followed by a
single stage of
high-temperature shift reactor, and then followed by 1120 abatement and CO2
recovery ("CO-
Rich Fuel"); and (iv) a Hz-rich stream made by the process of this disclosure
("Hz-Rich Fuel").
In all cases the following is assumed: 2.0 wet vol% excess 02, 60 F (16 C)
air & fuel gas.
[0060] As can be seen from TABLE I, compared to all other three fuel
gases, the Hz-rich
stream made by the process of this disclosure has a considerably smaller CO2
footprint from
the emission of the flue gas produced by the combustion. Even though the Hz-
Rich Fuel only
comprises H2 at a lightly higher concentration and CO at a slightly lower
concentration than
the comparative CO-Rich Fuel, the Hz-Rich Fuel demonstrated a markedly lower
CO2 footprint
(40% lower). This shows a significant advantage of the process of this
disclosure utilizing at
least two stages of shift reactors compared to using a single stage of high-
temperature shift
reactor only. While it is possible to purify the CO-Rich Fuel further to
produce a fuel gas having
a higher H2 concentration and a lower CO concentration comparable to the Hz-
Rich Fuel by
using additional equipment such as a PSA unit, the installation and operation
of a PSA unit add
much more investment and operation costs and reduce the energy efficiency of
the process than
the addition of the second shift reactor. Therefore, the process of this
disclosure achieves the
18
Date Regue/Date Received 2022-12-12
production of a Hz-rich fuel gas with low CO2 footprint with a reduced cost
and enhanced
energy efficiency.
TABLET
Fuel Gas Natural Gas Tailgas CO-
Rich Fuel Hz-Rich Fuel
Hydrogen 0.00 26.26 90.08 93.85
Methane 94.11 73.33 3.63 3.63
Ethane 4.76 0.23 0.00 0.00
^ Propane
0.64 0.03 0.00 0.00
iButane 0.30 0.02 0.00 0.00
=--, Ethylene 0.00 0.05 0.00
0.00
cl
.2 Propylene 0.00 0.00 0.00 0.00
,-
or" Butene 0.00 0.00 0.00 0.00
rg Carbon Monoxide 0.00 0.08 5.52 1.75
(...) Nitrogen 0.19 0.00 0.23 0.23
Carbon Dioxide 0.00 0.00 0.25 0.25
Water Vapor 0.00 0.00 0.29 0.29
Total 100.00 100.00 100.00 100.00
LHV (Btu/lb) 21295.5 22740.6
27059.5 35175.5
Lb fuel/MBtu 46.96 43.97 36.96 28.43
Lb flue-gas/Lb fuel 20.16 21.17 21.70 28.06
Lb flue-gas/MBtu 946.5 930.8 801.9 797.7
Flue-gas wt% CO2 13.68 12.41 4.57 2.77
Flue-gas vol% CO2 8.60 7.72 2.66 1.59
Lb/MBtu 129.49 115.51 36.65 22.10
1 Lb/MBtu as % of
Ei Natural Gas Firing 100 89 28 17
0 Lb/MBtu as % of
4-, 112 100 32 19
6 Tailgas firing
V Lb/MBtu as % of
353 315 100 60
CO-Rich Fuel Firing
11.2 Hydrocarbon Feed Integration
[0061] In one particularly advantageous embodiment, the CH4-rich stream
produced from
the olefins production plant may be fed into the syngas producing unit as at
least a portion of
the hydrocarbon feed, along with, e.g., a natural gas stream. Since the C114-
rich stream from
the olefins production plant can be substantially free of sulfur, it can be
advantageously fed
into the syngas producing unit after the sulfur-removal unit, if any. If the
CH4-rich comprises
C2+ hydrocarbons (e.g., ethane) at a low molar concentration, e.g., < 3%, <
2%, <1%, < 0.5%,
<0.1%, e.g., from 0.01%, 0.02%, 0.04%, 0.05%, to 0.06%, 0.08%, 0.1%, to 0.2%,
0.4%, 0.5%,
to 0.6%, 0.8%, 1%, 2%, or even 3%, based on the total moles of hydrocarbons in
the C114-rich
stream, then the CH4-rich stream can be supplied to the reforming reactor at a
location
19
Date Regue/Date Received 2022-12-12
downstream of the pre-reformer, if any, because of the reduced need to convert
the C2+
hydrocarbons in the pre-reformer. The CH4-rich stream may comprise H2 at
various quantities,
as indicated above. However, it is not necessary to remove the H2 from the CH4-
rich stream
before it is fed to the SMR. Excess hydrogen in the C114-rich stream can
consume hydraulic
capacity in the SMR and hence is undesirable. But a small amount of hydrogen
(preferably
mol%, preferably < 5 mol%, based on the total moles of molecules in the CH4-
rich stream)
is acceptable, and may actually serve to minimize the potential for coke or
foulant generation
in the SMR.
[0062] In certain embodiments, the CH4-rich stream may have a pressure
higher than the
10 pressure of the hydrocarbon feed required for feeding into the syngas
producing unit. In such
case, it is highly advantageous to expand the CH4-rich stream in a turbo-
expander and/or a
Joule-Thompson valve to produce a cooled CH4-rich stream having a pressure in
the vicinity
of the pressure of the hydrocarbon feed. The cooled CH4-rich stream may be
heated by using,
e.g., any stream in the olefins production plant or the Hz-rich production
unit having a
temperature higher than the cooled C114-rich stream, and then supplied to the
syngas producing
unit.
[0063] In certain embodiments, the CH4-rich stream may have a pressure
lower than the
pressure of the hydrocarbon feed required for feeding into the syngas
producing unit. In such
case, it is desirable to compress the CH4-rich stream to a pressure in the
vicinity of the pressure
of the hydrocarbon feed before feeding it to the syngas producing unit.
11.3 Steam Integration
[0064] In an olefins production plant including one more steam crackers,
a steam cracker
receives a hydrocarbon feed and steam, cracks the hydrocarbons under steam
cracking
conditions to produce a steam cracker effluent exiting the steam cracker. The
high-temperature
steam cracker effluent is immediately cooled by quenching and/or an indirect
heat exchanger,
where a significant amount of steam may be generated, which can be
subsequently superheated
in the convection section of the steam cracker. The cooled steam cracker
effluent can be then
separated to produce, among others, a process gas stream comprising H2,
methane, ethane, C2-
C4 olefins and dienes. To recover the olefins products from the process gas
stream, it is
typically first compressed to an elevated pressure, cooled in a chill train
under cryogenic
conditions, and then separated in distillation columns such as a demethanizer,
a deethanizer, a
depropanizer, a C2 splitter, a C3 splitter, and the like. To that end, at
least three (3) large gas
compressors: a process gas compressor ("PGC"), a propylene refrigeration
compressor
("PRC") and an ethylene refrigeration compressor ("ERC") may be used. In a
modern, world
Date Regue/Date Received 2022-12-12
scale olefins plant, the combined shaft power of these compressors can exceed
100 MW
(134,000 hp). This very high shaft power demand is a characteristic of olefms
production
plants, and differentiates them from most other petrochemical facilities.
Typically the large
compressors are driven by steam-turbines. The majority of the steam can be
generated by the
steam produced from cooling the steam cracker effluent as described above. If
necessary,
boilers are used to make-up the required steam volumes.
[0065] Because of the large shaft power requirements of the major
compressors, for
efficient olefin production it is important that the steam-power cycle be as
efficient as possible.
A multi-pressure-level steam system with the highest steam pressure level
being nominally 100
BarG (1500 psig, or 10.3 MPaG) or higher may be advantageously used. This
Super-HPS may
be superheated in order to maximize the specific power output (kW power/kg
steam consumed)
of the turbines. In addition to the large compressor steam turbines, smaller
turbine drivers may
be used for several services within the olefins production plant (e.g.:
cooling water pumps,
quench water pumps, boiler-feed water pumps, air compressors, etc.). These
turbines can
receive HPS, MPS, or LPS streams. In addition, process heating duties existing
in the olefins
recovery train may be satisfied by condensing one or more HIPS, MPS, or LPS
stream(s).
[0066] We have found that the steam stream(s) at various pressures
produced from and/or
consumed in an Hz-rich fuel gas production plant can be judiciously integrated
with the steam
stream(s) at various pressures produced from and/or consumed in an olefins
production plant
to achieve considerably enhanced overall energy efficiency and cost
efficiency. Thus, a Super-
HPS stream produced in an Hz-rich fuel gas production plant (e.g., a stream
produced from the
WHRU) may be advantageously combined with another Super-HPS stream produced in
an
olefins production plant (e.g., a stream produced from a steam cracker and/or
a boiler) to form
a joint stream, which is then supplied to consumers such as turbines, a syngas
production unit,
and the like, located in the plants. Likewise, HPS streams produced at the
plants may be
combined and supplied to consumers, so do the MPS streams, and the LPS
streams.
[0067] The reformed stream exiting the refoiming reactor of the Hz-rich
production plant
has a high temperature and high pressure as indicated above in section I. It
is highly desirable
to capture the heat energy contained therein. Thus, preferably, the reformed
stream passes
through a waste heat recovery unit ("WHRU") to produce a cooled reformed
stream and to
generate a high-pressure steam ("HPS") stream. The cooled reformed stream can
have a
temperature from, e.g., 285 C, 290 C, 300 C, to 310 C, 320 C, 330 C, 340
C, 350 C, to
360 C, 370 C, 380 C, 390 C, or even 400 C. The cooled reformed stream can
have a
pressure substantially the same as the reformed stream exiting the reforming
reactor. The
21
Date Regue/Date Received 2022-12-12
WHRU can include, e.g., one or more heat exchanger and one or more steam drum
in fluid
communication with the heat exchanger. The steam drum supplies a water stream
to the heat
exchanger, where it is heated and can be then returned to the steam drum,
where steam is
separated from liquid phase water. The HPS stream can have an absolute
pressure from, e.g.,
4,000 kPa, 5,000 kPa, 6,000 kPa, 7,000 kPa, 8,000 kPa, to 9,000 kPa, 10,000
kPa, 11,000 kPa,
12,000 kPa, 13,000 kPa, or even 14,000 kPa. In certain embodiments, the HPS
stream is
preferably a Super-HPS stream. The thus produced HPS stream is a saturated
steam stream.
[0068] To make the HPS stream more useful, it may be further heated to
produce a
superheated HPS ("SH-HPS") stream in, e.g., a furnace. In case the syngas
producing unit
comprises an SMR having a convection section as described above, the saturated
HPS stream
may be advantageously superheated in the convection section of the SMR and/or
in an auxiliary
furnace. In case the syngas producing unit comprises one or more ATR but no
SMR, the
saturated HPS stream can be superheated in an auxiliary furnace. The auxiliary
furnace can
include one or more burners combusting a fuel gas stream to supply the needed
thermal energy
as is known to one skilled in the art, preferably a fuel gas stream derived
from the Hz-rich
stream produced in an Hz-rich fuel gas production plant and/or the steam
cracker Hz stream
produced in an olefins production plant as described above. The SH-HPS stream
can have one
of both of: (i) a temperature from, e.g., 350 C, 360 C, 370 C, 380 C, 390
C, 400 C, to 410
C, 420 C, 430 C, 440 C, 450 C, to 460 C, 470 C, 480 C, 490 C, 500 C,
to 510 C,
520 C, 530 C, 540 C, or even 550 C; and (ii) an absolute pressure from,
e.g., e.g., 4,000
kPa, 5,000 kPa, 6,000 kPa, 7,000 kPa, 8,000 kPa, to 9,00010a, 10,000 kPa,
11,000 kPa, 12,000
kPa, 13,000 kPa, or even 14,000 kPa. Preferably the SH-HPS stream has a
temperature of at
least 371 C and the steam feed in step (A) has an absolute pressure of at
least 1700 kPa. In
certain embodiments, the SH-HPS stream preferably has a pressure higher than
that of the
steam feed supplied to the syngas producing unit in step (A), so that the SH-
HPS can be
expanded to produce a steam stream having a pressure in the vicinity of the
pressure of the
steam feed, which can then be supplied to the syngas producing unit as at
least a portion of the
steam feed. Preferably the SH-HPS stream has a temperature of at least 482 C
and an absolute
pressure of at least 10,000 kPa, and the steam feed has an absolute pressure
of at least 1,700
kPa (e.g., at least 2,500 kPa). In a preferred embodiment, the SH-HPS stream
may be supplied
to an HPS header located in an industrial plant, such as an olefins production
plant, and an H2-
rich fuel gas production plant, supplying HPS to suitable equipment consuming
SH-HPS. In
another embodiment, the SH-HPS stream may be also a Super-HPS stream, and
supplied to a
22
Date Regue/Date Received 2022-12-12
Super-HPS header located in an industrial plant, such as an olefins production
plant, supplying
Super-HPS to suitable equipment consuming superheated Super-HPS.
[0069] In certain preferred embodiments, at least a portion of an SH-HPS
stream derived
from a steam stream produced in a H2-rich fuel production plant (e.g., the SH-
HPS stream
produced at the WHRU) and/or a steam stream produced from an olefins
production plant (e.g.,
an SH-HPS stream produced from a steam cracker and/or a boiler) can be
expanded in at least
one stage of a steam turbine to produce shaft power and an expanded steam
stream having a
pressure equal to or higher than that of the steam feed to the syngas
producing unit. The
expanded steam stream may have a temperature from, e.g., 260 C, 270 C, 280
C, 290 C,
300 C, to 310 C, 320 C, 330 C, 340 C, 350 C, to 360 C, 370 C, 380 C,
390 C, 400
C, or even 405 C. The expanded steam stream has a pressure lower than the SH-
HPS stream,
which may range from, e.g., 1,380 kPa, 1,400 kPa, 1,500 kPa, 1,600 kPa, 1,700
kPa, 1,800 kPa,
1,900 kPa, 2,000 kPa, to 2,200 kPa, 2,400 kPa, 2,500 kPa, 2,600 kPa, 2,800
kPa, 3,000 kPa, to
3,200 kPa, 3,400 kPa, 3,500 kPa, 3,600 kPa, 3,800 kPa, 4,000 kPa, to 4,200
kPa, 4,400 kPa, or
even 4,500 kPa. The expanded steam stream may be an HPS stream, or an MPS
stream. The
steam turbine may produce multiple exhaust streams in certain embodiments,
e.g., an HPS
stream and an LPS stream; an HPS stream and a condensable stream supplied to a
condenser;
an MPS stream and an LPS stream; or an MPS stream and a condensable stream
supplied to a
condenser.
[0070] In certain embodiments, a single stage of steam turbine is used for
expanding the
SH-HPS stream_ In certain other embodiments, multiple cascading stages of
steam turbines
may be used, where an expanded steam stream produced from an upstream stage,
preferably
an HPS stream or an MPS stream, is supplied to a downstream steam turbine,
expanded therein
to produce a lower pressure steam stream and additional shaft power. The shaft
power
produced by the one or more such steam turbines can be used to perform
mechanical work such
as: driving a generator to produce electrical power transmissible to local
and/or distant
electrical equipment; driving a compressor or pump located in an industrial
plant, such as a
process gas compressor, a propylene refrigeration compressor, an ethylene
refrigeration
compressor, an air compressor, and/or various pumps located in an olefins
production plant.
The expanded steam stream may be supplied to a steam header with the suitable
pressure rating
located in any industrial plant such as an olefins production plant. In
certain embodiments, the
SH-HPS stream may be supplied to an olefins production plant at a pressure no
less than the
maximal pressure required for the operation of any steam turbine having a
power rating of at
least 1 megawatt (1 MW, or? 5 MW, or? 10 MW, or? 20 MW) in the olefins
production
23
Date Regue/Date Received 2022-12-12
plant. In certain preferred embodiments, the SH-HPS stream (which may or not
be a Super-
HPS stream) may be supplied to a first stage steam turbine that drives a
process gas compressor
in an olefins production plant, and the expanded steam stream from the first
stage steam turbine,
which may be an SH-HPS stream or an MPS stream, may be supplied to a second
stage steam
turbine producing a second expanded steam stream and shaft power driving
another process
gas compressor, a propylene refrigeration compressor, an ethylene
refrigeration compressor,
an air compressor, and/or a pump in the olefins production plant. In another
embodiment, the
SH-HPS stream may be supplied to drive one or more process gas compressors, a
propylene
refrigeration compressor, and an ethylene refrigeration compressor, each
producing an
expanded steam stream having the same, similar, or different pressure. The
expanded steam
streams from the first stage and/or the second stage can then be used to
provide process heat,
or supplied to additional steam turbines, depending on their respective
pressures. In addition,
one or more of the steam turbines may exhaust a condensable steam stream fed
to a condenser
to produce a condensate water stream. Preferably, at least one, preferably at
least two,
preferably all, of the steam turbines driving the PGCs, the propylene
refrigeration compressors,
and the ethylene refrigeration compressors are back-pressure steam turbines.
Back-pressure
turbines do not produce a steam stream supplied to a surface condenser, where
it is condensed
resulting in release of thermal energy to the atmosphere. By using back-
pressure turbines,
conventional surface condensers used in conventional condensing turbines are
eliminated,
resulting in reduction of capital and operational costs, as well as release of
thermal energy to
the atmosphere.
[0071] While the shaft power produced in expanding the SH-HPS stream may be
used to
drive an electricity generator in a power island, in preferred embodiments of
this disclosure
where the shaft power is used to drive compressors, pumps, and the like in an
integrated olefms
production plant, such power island can be eliminated or included at a smaller
size, resulting
in considerable reduction in capital costs and operation costs.
[0072] In certain preferred embodiments of the Hz-rich fuel gas
production process, step
(VII) of recovering the at least a portion of the CO2 present in the crude gas
mixture stream to
produce a CO2 stream and a Hz-rich stream is carried out using an amine CO2
capture unit. Step
(VII) may preferably comprise: (VIIa) obtaining an exhaust steam stream having
an absolute
pressure from 200 kPa to 1,050 kPa and shaft power from one or more extraction
turbine(s)
and/or back-pressure turbine(s) (preferably one or more back-pressure
turbine(s)) located in a
an olefins production plant; (VIIb) feeding the crude gas mixture stream and a
lean-amine
stream comprising an amine into an absorption column; (VIIc) obtaining a CO2-
rich amine
24
Date Regue/Date Received 2022-12-12
stream and a CO2-depleted residual gas stream from the absorption column;
(VIId) feeding at
least a portion of the CO2-rich amine stream into a separation column; (Vile)
heating the at
least a portion of the CO2-rich amine stream in the separation column using an
exhaust steam
stream to produce an overhead stream rich in CO2 and a bottoms stream rich in
the amine; and
(VIII) recycling at least a portion of the bottoms stream to the absorption
column as at least a
portion of the lean-amine stream.
[0073] The extraction turbine(s) and/or back-pressure turbine(s) in step
(VIIa) is present in
an olefins production plant. Historically these steam turbines located in
hydrocarbon
processing plants are routinely configured to produce an exhaust steam streams
having a very
low pressure, e.g., < 100 kPa, < 80 kPa, < 50 kPa, which are then supplied to
and condensed at
surface condensers with large duty ratings. Such condensing can result in
release of significant
amount of thermal energy into the atmosphere. In addition, surface condensers
having large
duty ratings are expensive to buy and operate. Therefore, it would be highly
desirable to reduce
the size of the surface condensers or eliminate at least some, preferably all,
of them without
causing problems to the operation of the devices driven by the steam turbines.
[0074] The extraction turbine(s) and/or back-pressure turbine(s) in step
(Vita) may receive
an HPS feed such as a Super-HPS feed, or an MPS feed, desirably superheated.
Depending on
the pressure of the steam feed thereto, one or more of the extraction
turbine(s) and/or back-
pressure turbine(s) may produce, in addition to the exhaust steam stream
having an absolute
pressure from 200 kPa to 1,050 kPa, one or more of: (i) an HPS stream; (ii) an
MPS stream;
and (iii) a condensable stream supplied to a surface condenser. Preferably at
least one,
preferably all, of the extraction turbine(s) and/or back-pressure turbine(s)
is a back-pressure
turbine that does not produce (iii) a condensable stream (e.g., a steam stream
having an absolute
pressure < 100 kPa) supplied to a surface condenser. The extraction turbine(s)
and/or back-
pressure turbine(s) can include one or more of: the steam turbines driving the
process gas
compressors; the steam turbine(s) driving the propylene refrigeration
compressor(s); the steam
turbine(s) driving the ethylene refrigeration compressor(s); the steam
turbine(s) driving various
air compressors; the steam turbine(s) driving various pumps; and the steam
turbine(s) driving
electricity generator(s), and combinations thereof.
[0075] The exhaust steam stream having an absolute pressure from 200 kPa to
1,050 kPa
may be produced by a single extraction turbine or back-pressure turbine.
Alternatively, the
exhaust steam stream can be a joint stream of several such exhaust steam
streams having similar
pressures produced from multiple extraction turbine(s) and/or back-pressure
turbines. This
pressure range is particularly advantageous for supplying heat needed in the
regeneration step
Date Regue/Date Received 2022-12-12
of an amine CO2 capture process. Thus, the exhaust steam stream can have an
absolute pressure
from, e.g., 200 kPa, 250 kPa, 300 kPa, 350 kPa, 400 kPa, 450 kPa, 500 kPa, to
550 kPa, 600
kPa, 650 kPa, 700 kPa, 750 kPa, 800 kPa, to 850 kPa, 900 kPa, 950 kPa, 1,000
kPa, or even
1,050 kPa. Preferably, the exhaust steam stream has an absolute pressure of no
greater than
480 kPa.
[0076] In step (VIlb), the gas mixture stream and a lean-amine stream
comprising an amine
are fed into an absorption column. Any amine absorption column and amine known
to one
skilled in the art of CO2 separation may be used. Non-limiting examples of
useful amine
include: monoethanolamine ("MEA"), diethanolamine ("DEA"),
methyldiethanolamine
("MDEA"), diisopropanolarnine ("DIPA"), diglycolamine ("DGA"), and mixtures
thereof.
The most commonly used amines for CO2 separation and capture are DEA, MEA, and
MDEA.
In a preferred embodiment, the lean-amine stream is supplied to the upper
section of the
absorption column, and the gas mixture is fed into a lower section of the
absorption column.
Counter-current contacting between the gas mixture and the amine in the
absorption column
results in producing a CO2-rich amine stream and a CO2-depelted residual gas
stream in step
(VIIc). Preferably the CO2-rich amine stream exits the absorption column from
the bottom and
the CO2-depleted residual gas stream from the top.
[0077] In step (VIId), at least a portion of the CO2-rich amine stream
is fed into a separation
column. Any design of the separation column known to one skilled in the art
may be used. The
separation column is sometimes also called a regeneration column in that the
amine is
regenerated from this column. In step (VIId), at least a portion of the CO2-
rich amine stream is
heated in the separation column. Such heating can be effected by using a heat
exchanger. At
least a part, preferably 30%, preferably 50%, preferably 60%, preferably 80%,
preferably
> 90%, preferably the entirety, of the themial energy used for the heating is
provided by the
exhaust steam stream produced in step (VIId). Upon being heated to a desirable
temperature,
the CO2 separates from the amine in the separation column, resulting in a C 02-
rich stream and
a stream rich in the amine. Preferably, the CO2-fich stream exits the
separation column at the
top, and the stream rich in the amine from the bottom. The stream rich in the
amine can be at
least partly recycled to the absorption column as at least a portion of the
lean-amine stream in
step (vii). The CO2-rich stream can be compressed, liquefied, conducted away,
stored,
sequestered, or utilized in any suitable applications known to one skilled in
the art. In one
embodiment, the CO2¨rich stream, upon optional compression, can be conducted
away in a
CO2 pipeline. In another embodiment, the CO2¨rich stream, upon optional
compression and/or
liquefaction, can be injected and stored in a geological formation. In yet
another embodiment,
26
Date Regue/Date Received 2022-12-12
the CO2¨rich stream, upon optional compression and/or liquefaction, can be
used in extracting
hydrocarbons present in a geological formation. Another exemplary use of the
CO2¨rich stream
is in food applications.
[0078] The exhaust steam stream produced from the extraction turbine(s)
and/or back-
pressure turbine(s) in step (VIIa) having an absolute pressure from 200 kPa to
1,050 kPa
(preferably no greater than 800 kPa, preferably no greater than 500 kPa,
preferably no greater
than 480 kPa) is particularly suitable for supplying heat to the separation
column to effect the
separation of CO2 from the amine. One skilled in the art can extract the
suitable quantity of the
exhaust steam stream from the one or more extraction turbine(s) and/or back-
pressure
turbine(s), as illustrated below in this disclosure, to satisfy the heating
duty needed in the
CO2/amine separation/regeneration column to effect the separation of any given
quantity of the
crude gas mixture with any CO2 concentration therein. By producing the exhaust
steam stream
and supplying the same to the separation column, residual thermal energy in
the exhaust steam
stream is utilized to perform useful work. This is in contrast to the prior
art of producing a
condensable steam stream further condensed in a surface condenser, where
residual thermal
energy in the condensable stream is released to the atmosphere and lost. When
an olefins
production plant including multiple large steam turbines is steam-integrated
with an amine
CO2-separation process according to the various embodiments of this
disclosure, substantial
improvement in energy efficiency can be achieved, as demonstrated by the
Examples in this
disclosure below. Moreover, extraction of such exhaust steam stream(s) can be
carried out in
one or more back-pressure turbines, such that each turbine can still produce
sufficient amount
of shaft power for driving the target equipment. In certain embodiments, it
may be desirable to
increase steam feed to one or more of the extraction turbine(s) and/or back-
pressure turbines
to ensure the production of both sufficient amount of shaft power and the
exhaust steam stream.
To that end, in certain specific embodiments, one may replace an existing
steam turbine with
an electric motor, so that the steam required by the replaced steam turbine
can be supplied to
an extraction turbine and/or a back-pressure turbine producing the exhaust
steam stream and
the shaft power in sufficient amount. In certain embodiments, the exhaust
steam stream is
produced from a back-pressure turbine, and the exhaust stream provides a
quantity of energy
to the at least a portion of the CO2-rich amine stream in step (VIIe); and at
least 30%
(preferably 50%, preferably 60%, preferably 70%) of the quantity of energy
would have
been lost to the atmosphere in a comparative process identical with the
process except the back-
pressure turbine is substituted by an extraction/condensing turbine with the
identical power
rating.
27
Date Regue/Date Received 2022-12-12
[0079] This disclosure is further illustrated by the exemplary but non-
limiting embodiments
shown in the drawings, which are described below. In the drawings, the same
reference numeral
may have similar meanings. In the drawings illustrating an inventive
process/system, where
multiple initially separate streams are shown to form a joint stream supplied
to a next step or
device, it should be understood to further include, where appropriate, an
alternative where at
least one of such multiple separate streams is supplied to the next step or
device separately.
Where multiple initially separate streams having similar compositions and/or
use applications
(e.g., the Hz-rich stream and the steam cracker H2 stream) are shown to form a
joint stream
supplied to multiple next steps or devices, it should be understood to
include, where appropriate,
alternatives where at least one of the separate streams and the j oint stream
is supplied to at least
one of the multiple next steps or devices. Thus, where a fuel gas (e.g., an Hz-
rich stream) X
and a fuel gas stream (e.g., a steam cracker H2 stream) Y, initially separate
and generated from
differing devices but with similar fuel gas applications, are shown to folin a
joint stream Z
supplied to two separate furnaces A and B, it should be understood to include
alternatives where
at least one of X, Y, and Z is supplied to at least one of A and B, including
but not limited to
the following: (i) only stream Z is supplied to A and B; (ii) both of X and Y
are supplied,
separately, to at least one of A and B; (iii) both of X and Z are supplied,
separately, to at least
one of A and B; (iv) both of Y and Z are supplied, separately, to at least one
of A and B; and
(v) only one of X and Y is supplied to at least one of A and B. The drawings
are only for the
purpose of illustrating certain embodiments of this disclosure, and one
skilled in the art
appreciates that alternatives thereof may fall within the scope of this
disclosure.
FIG. 1 (Comparative)
[0080] FIG. 1 schematically illustrates a steam supply/consumption system 101
of a
conventional olefins production plant including one or more steam cracker
furnaces. One or
more Super-HPS stream(s)) 107 are produced from one or more steam cracker
furnace(s) 103.
One or more Super-HPS stream(s) 109 are produced from one or more auxiliary
steam boiler(s)
or COGEN units 105. Streams 107 and 109 may be optionally combined, as shown,
at a Super-
HPS header, from which the Super-HPS stream can be distributed to equipment
consuming
steam. As shown in FIG. 1, one or more Super-HPS stream(s) 113, one or more
Super-HPS
stream(s) 115, and one or more Super-HPS stream(s) 117 are supplied to one or
more steam
turbine(s) 119, one or more steam turbine(s) 129, and one or more steam
turbine(s) 141,
respectively. Steam turbine(s) 119 can drive one or more process gas
compressor(s). Steam
turbine(s) 129 can drive one or more propylene refrigeration compressors.
Steam turbine(s)
141 can drive one or more ethylene refrigeration compressors. Additional Super-
HPS steam
28
Date Regue/Date Received 2022-12-12
may be supplied to other facilities/equipment/process 111 for consumption.
From steam
turbine(s) 119, one or more HPS stream(s) 121 may be exhausted. Stream(s) 121
can be used
to provide process heat, e.g., to a stream 125 in the olefins production plant
or other facilities,
or supplied to a steam turbine 125 receiving an HPS stream and exhausting a
MPS stream, or
supplied to a steam turbine 125 receiving an HIPS stream and exhausting an LPS
stream, to
produce additional mechanical work which can be used to drive another process
gas
compressor, pumps, and the like. From steam turbine(s) 119, one or more
condensable stream(s)
123 are typically exhausted, which are condensed at condenser(s) 127 to
produced one or more
condensed water stream(s) 128. From steam turbine(s) 129, one or more MPS
stream(s) 131
may be exhausted. Stream(s) 131 can be used to provide process heat, e.g., to
a stream 133 in
the olefins production plant or other facilities, or supplied to a steam
turbine 133 receiving a
MPS stream and exhausting an LPS stream, to produce additional mechanical work
which can
be used to drive another compressor, pumps, and the like. From steam
turbine(s) 129, one or
more condensable stream(s) 135 are exhausted, which are then condensed at
condenser(s) 137
to produce one or more condensed water stream(s) 139. From steam turbine(s)
141, one or
more LPS stream(s) 143 may be exhausted. Stream(s) 143 can be used to provide
process heat,
e.g., to a stream 145 in the olefins production plant or other facilities.
From steam turbine(s)
141, one or more condensable stream(s) 147 are exhausted, which are then
condensed at
condenser(s) 149 to produce one or more condensed water stream(s) 151.
Condensed water
.. streams 128, 139, and 151 are then combined and processed together at
location 353. The
production of condensable steam streams 123, 135, and 147, which are
subsequently condensed
using surface condensers, can increase the shaft power production of turbines
119, 129, and
141. However, the condensing of them result in release of substantial quantity
of thermal
energy released to the atmosphere. In addition, the surface condensers 127,
137, and 149
require substantial capital investment and operational costs.
FIG. 2 (Comparative)
[0081] FIG. 2 schematically illustrates a comparative H2 production plant
including an SMR.
As shown, a natural gas feed stream 202, which may contain CH4, C2+
hydrocarbons at various
concentrations, and sulfur-containing compounds at various concentrations, is
split into steams
203 and 204. Stream 203 is first fed into a sulfur removal unit 205 to produce
a sulfur-abated
stream 207. Stream 207 is combined with a steam stream 279 to form a
hydrocarbon/steam
mixture stream 209. Stream 209 is then fed into a pre-reformer 211 containing
a pre-reforming
catalyst therein. On contacting the pre-reforming catalyst, the heavier C2+
hydrocarbons are
preferentially converted into methane (thus preventing the formation of coke
in the downstream
29
Date Regue/Date Received 2022-12-12
primary reforming reactor) to produce a pre-reforming effluent 213 comprising
methane and
steam. Stream 213 is then fed into a tube 220a in the upper section 214,
sometimes called
convection section, of an SMR 215, where it is heated. SMR 215 comprises a
lower section
216, sometimes called radiant section, housing one or more tube 220b which is
in fluid
communication with tube 220a receiving the stream 213 heated in tube 220a. As
shown, in
certain embodiments, a tube 220a may exit the convection section to the
exterior of the SMR
furnace, and then connect with tube(s) 220b, which re-enter the SMR furnace.
Multiple tubes
220b may be connected with one tube 220a via one or more manifold (not shown)
outside of
the SMR furnace housing, though one tube 220b is shown. SMR 215 comprises one
or more
burners 218 in the radiant section 216, where a SMR fuel combusts to supply
energy to the
radiant section 216 and then the convection section 214 of SMR 215.
[0082] A reforming catalyst is loaded in tube(s) 220b in the radiant section
216. Due to the
proximity to the burner(s) 218, the CH4 and steam mixture, and the reforming
catalyst in tube(s)
220b are heated/maintained at an elevated temperature. The forward reaction of
the following
preferentially occurs:
Reforming Catalyst
CH4 + H20 - CO + 3 H2
(R-1)
[0083] In addition, various amounts of CO2 may be produced in tube(s) 220b.
Thus, a
refoimed stream 221 comprising CO, H2, residual CH4, residual H20 and
optionally various
amount of CO2 exits the outlet of tube(s) 220b from the SMR. Stream 221 is
then cooled at a
.. waste heat recovery unit ("WHRU") including a waste heat boiler ("WHB") 223
and a steam
drum 271 to produce a cooled refouned stream 225 and to generate an HPS stream
267. As
shown, a water stream 263 flows from steam drum 271 to WHB 223, and a steam-
water mixture
stream 265 flows from WHB 223 to steam drum 271.
[0084] Stream 267, a saturated steam stream, is then heated in the convection
section 214 of
SMR 215 to produce a super-heated, high-pressure steam ("SP-HP") steam stream
269. A split
stream 279 of stream 269 is combined with the sulfur-abated hydrocarbon feed
stream 207 to
form a combined stream 209, which is then fed into the pre-reformer 211 as
described above.
Another split stream 277 of stream 269 is fed into a steam turbine 173, where
it is expanded to
produce an exhaust steam stream 283 and shaft power driving an electricity
generator via shaft
281. Exhaust steam stream 283 may be condensable and condensed using a surface
condenser.
[0085] As shown in FIG. 2, the cooled reformed stream 225, comprising CO, Hz,
H20, and
optionally CO2, is then fed into a shift reactor 227 containing a shift
catalyst loaded therein.
Date Regue/Date Received 2022-12-12
On contacting the shift catalyst under the shifting conditions, the forward
reaction of the
following preferentially occurs:
Shift Catalyst
CO + H20 - _________________________________ - __ CO2 +H2
(R-2')
Thus, a shifted stream 229 comprising CO at a lower concentration than stream
225 and CO2
at a higher concentration than stream 225 exits the shift reactor 227.
[0086] The shifted stream 229 is then cooled down at heat exchanger 231 by a
boiler feed
water stream 234, supplied from a boiler feed water treatment unit 233. The
thus heated boiler
feed water stream 235 exiting the heat exchanger 231 is then supplied to steam
drum 271 and
at least partly supplied to the WI-TB 223, to produce high-pressure steam
stream 267 as
described earlier.
[0087] The cooled shifted stream 236 exiting heat exchanger 231, comprising
CO, Hz, H20,
and CO2, is then further cooled down at heat exchanger 245. A portion of the
residual steam
in stream 236 is condensed to liquid water in stream 247, which can be fed
into a separator 249
to obtain a condensate stream 251 and a vapor stream 253. The steam-abated
stream 253
comprises primarily H2 and CO2, CH4 and CO.
[0088] Stream 253 is then supplied into a pressure-swing ("PSA") unit 255 to
produce an H2
stream 257 and a PSA reject stream 259 comprising CO, CO2, CH4, and Hz, is
then fed into
SMR 215, along with a split natural gas stream 204, as SMR fuel, which is
combusted at
burner(s) 218 to provide the thermal energy needed for the radiant section and
convention
section of SMR 215. The PSA reject stream 215 typically comprises H2 no
greater than 30
vol%, based on the total volume of stream 215.
[0089] In the H2 production process 201 of FIG. 2, due to the combustion of
natural gas from
stream 204 and the carbon-rich PSA reject stream 259, the flue gas stream 219
exiting SMR
215 comprises CO2 at considerably high concentration. While it is possible to
capture the CO2
from stream 219 to reduce CO2 emission from process 201 by using an amine
absorption/regeneration unit, such unit requires high capital expense, and
because stream 219
is at atmospheric pressure, high operational expense as well. The PSA unit 255
also requires
significant capital and operational expense.
FIG. 3
[0090] FIG. 3 schematically illustrates a comparative process/system 301 where
H2 is
supplied from a H2 production process similar to that of FIG. 2 to an olefins
production plant
including one or more steam cracker furnaces. As shown, a split stream of
natural gas stream
303 is combined with a steam stream 305 to form a joint stream 307, which is
fed into a tube
31
Date Regue/Date Received 2022-12-12
located in the convection section 309 of an SMR and heated therein, and then
enters a tube
containing a refolining catalyst in the radiant section 311 of the SMR. The
SMR receives a
SMR fuel gas stream 317, which combusts in the SMR to generate the thermal
energy heating
the radiant section 311 and the convection section 309. On contacting the
reforming catalyst,
the CH4/steam mixture undergoes reforming reaction to produce a refonned gas
stream 319
comprising CO, CO2, H2, and CH4 exiting the SMR. Stream 319 is then cooled
down at waste-
heat recovery unit 321 to obtain a cooled reformed stream 323 and an HPS
stream 301. Stream
301 is then heated in the convection section of the SMR to obtain a SH-HPS
stream 343. A
split steam 305 of stream 343 is combined with natural gas feed stream to form
the mixture
stream 307 fed into the SMR, as discussed above. Another split stream 345 of
stream 343 is
then fed into steam turbine 347, where it is expanded to produce shaft power
driving an
electricity generator 351 via shaft 349. The exhaust steam stream 353 from
turbine 347, a LPS
stream, can be sent to an amine regenerator of a CO2 capture unit 355, as
described below.
[0091] The cooled reformed stream 323 is then fed into a shift reactor 325,
where it contacts
a shift catalyst to effect the conversion of a quantity of CO/H20 into CO2 and
H2 to produce a
shifted stream 327 exiting the shift reactor 325. Stream 327 is then cooled
down at heat
exchanger 239 to produce a cooled shifted stream 331 containing condensed
water. In water
separator 333, a condensed water stream 335 is separated from stream 331 to
produce a steam-
abated stream 337 comprising primarily H2, CO2, and CO. Stream 337 is then fed
into a PSA
unit 339 to produce a H2 stream 341 and a PSA reject stream 315. Stream 315,
comprising CO,
CO2, and H2, is combined with natural gas stream 313 to folin a SMR fuel gas
stream 317.
Stream 317 is combusted in the SMR to generate the thermal energy heating the
radiant section
311 and the convection section 309 as described above. Flue gas stream 357
exiting the SMR
contains considerable quantity of CO2. To reduce CO2 footprint of the H2
production plant,
stream 357 is fed into the amine CO2 capture unit 355 as described above. In
unit 355, an
amine regenerator is heated by steam stream 353 to effect the separation of a
CO2 stream 359
exiting unit 355. CO2 stream 359 can be transferred via a pipeline, stored,
sequestered, or
utilized.
[0092] As shown in FIG. 3, the H2 stream 341, or a portion thereof, is then
supplied to a
steam cracker 371 located in an olefins production plant as stream 367 as a
steam cracker fuel,
where it combusts to provide the thermal energy needed for the cracking and
heating of a steam
cracker feed and to generate a flue gas stream 378 exiting the steam cracker
371. If the H2
stream 367 comprises high-purity H2 (e.g., with a H2 concentration 99 mol%),
then the flue
gas stream 378 may be substantially free of CO2. A steam cracker hydrocarbon
feed stream
32
Date Regue/Date Received 2022-12-12
369 and a dilution steam stream enter steam cracker 371, heated in a
convection section thereof,
and then enter into a radiant section where cracking occurs at high
temperature for a short
residence time to produce a steam cracker effluent comprising H2, Cl-C4
hydrocarbons
comprising the desirable C2-C4 olefins, and C5+ hydrocarbons, among others.
The steam
cracker effluent is immediately cooled down via quenching and/or indirect heat
exchange in
steam cracker 371, producing a quenched steam cracker effluent stream 375 and
a substantial
quantity of HPS which is then superheated to produce an SH-HPS stream 376. The
quenched
steam cracker effluent stream 375 is sent to the hot-ends 378 of the recovery
section where it
is further cooled. In section 378 a dilution steam 373 is generated which is
sent to steam cracker
371. Optionally, a split stream 361 of Hz stream 341 may be supplied to one or
more boilers
363 to produce additional amount of SH-HPS in stream 365. Streams 365 and 376
are combined
to form stream 377. Separation of the cooled steam cracker effluent stream 375
produces a
process gas stream comprising Hz and C 1-C4 hydrocarbons including the desired
C2-C4
olefins. The process gas stream is compressed in compressor(s) 380 to an
elevated pressure,
supplied to the cold end 379 of the recovery section to produce, among others,
a tailgas stream
390 consisting essentially of CH4 and Hz; an ethylene product stream 391; a
propylene product
stream 392; and one or more C4+ co-product streams 393, among others.
[0093] The SH-HPS stream 377 is supplied to one or more steam turbine(s)
driving one or
more process gas and/or refrigeration compressors 380. An HPS stream 381 may
be produced
from one or more turbines and fed to another turbine, or used to provide a
process heating duty.
An MPS stream 383 may be produced from one or more turbines, split into a
stream 386 which
is fed to another turbine or used to provide a process heating duty, and a
stream 385 which is
fed to the hot end 378 of the recovery section to generate dilution steam. An
LPS stream 382
may be produced from one or more turbines and used to provide a process
heating duty. The
turbines may exhaust one or more condensable streams 384, which is supplied to
one or more
surface condensers 387, where it is cooled by a cooling water stream 388 to
produce a
condensate stream 389.
[0094] In the process 301, CO2 emissions from steam cracker(s) 371 is reduced
by
combusting H2 from the Hz stream 367 compared to conventional steam cracker(s)
combusting
natural gas, or methane-rich tail-gas, or a combination of natural-gas and
methane-rich tail-gas;
CO2 emissions from boiler(s) 363 can be reduced if H2 stream 361 supplies the
fuel gas thereto
compared to conventional boilers combusting natural gas or a mixture of
natural-gas and
methane-rich tail-gas; and CO2 emission is reduced by capturing CO2 stream 359
from the
SMR flue gas stream 357 using the amine absorption/regeneration unit 355
compared to a
33
Date Regue/Date Received 2022-12-12
conventional H2 production plant using an SMR combusting natural gas without
capturing CO2
from the SMR flue gas. Nonetheless, the process 301 has the following
drawbacks: a high
capital cost due to the many equipment required; substantial cost of operating
the amine CO2
capture unit 355 due to the large volume of flue gas 357 at atmospheric
pressure; and the loss
of thermal energy to the atmosphere due to the use of surface condenser(s)
387.
FIG. 4
[0095] FIG. 4 schematically illustrates an exemplary Hz-rich fuel gas
production
process/plant 401 of this disclosure according to certain preferred
embodiments. As shown, a
hydrocarbon feed stream 403 (e.g., a natural gas stream comprising primarily
CH4), which may
contain C114, C2+ hydrocarbons at various concentrations, and sulfur-
containing compounds
at various concentrations, is first fed into an optional sulfur removal unit
405 to produce a
sulfur-abated stream 407, to prevent poisoning catalysts used in the
downstream process steps
such as the catalyst used in the SMR unit described below. Upon optional
preheating via, e.g.,
a heat exchanger or a furnace (not shown), stream 407 is combined with an HPS
stream 479 to
form a hydrocarbon/steam mixture stream 409. Upon optional preheating via,
e.g., a heat
exchanger or a furnace (not shown), stream 409 can be then fed into a pre-
reformer 411 which
can be an adiabatic reactor containing a pre-reforming catalyst therein. On
contacting the pre-
reforming catalyst, the heavier C2+ hydrocarbons are preferentially converted
into methane
(thus preventing the formation of coke in the downstream primary reforming
reactor) to
produce a pre-reforming effluent 413 comprising methane and steam. Stream 413
is then fed
into a tube 420a in the upper section 414, sometimes called convection
section, of an SMR 415,
where it is heated. SMR 415 comprises a radiant section 416, housing one or
more tube 420b
which is in fluid communication with tube 420a receiving the stream 413 heated
in tube 420a.
As shown in FIG. 4, in certain embodiments, a tube 420a may exit the
convection section to
the exterior of the SMR furnace, and then connect with tube(s) 420b, which re-
enter the SMR
furnace. Multiple tubes 420b may be connected with one tube 420a via one or
more manifold
(not shown) outside of the SMR furnace housing, though one tube 420b is shown.
SMR 415
comprises one or more burners 418 in the radiant section 416, where a SMR fuel
combusts to
supply energy to the radiant section 416 and then the convection section 414
of SMR 415. For
the convenience of illustration, tubes 420a and 420b in the SMR are shown as
comprising
multiple straight segments. In practice, certain portions of tubes 420a and
420b, particularly
tube 420a, may be curved, or even form serpentine windings.
[0096] A reforming catalyst is loaded in tube(s) 420b in the radiant section
416. Due to the
proximity to the burner(s) 418, the hydrocarbon feed and steam, and the
reforming catalyst in
34
Date Regue/Date Received 2022-12-12
tube(s) 420b are heated/maintained at an elevated temperature. The forward
reaction of the
following preferentially occurs under syngas producing conditions:
Reforming Catalyst
CH4 -I- H20 . CO + 3 H2
(R-1)
[0097] In addition, various amounts of CO2 may be produced in tube(s) 420b.
Thus, a
reformed stream 421 comprising CO, Hz, residual CH4, residual H20 and
optionally various
amount of CO2 exits the outlet of tube(s) 420b from the SMR at a temperature
of, e.g., from
750 C to 900 C and an absolute pressure of, e.g., from 700 kPa to 3,500 kPa.
Stream 421 is
then cooled at a waste heat recovery unit ("WHRU") including a waste heat
boiler ("WHB")
423 and a steam drum 471 to produce a cooled reformed stream 425 and to
generate an HPS
stream 467. As shown, a water stream 463 flows from steam drum 471 to WHB 423,
and a
steam-water mixture stream 465 flows from WHB 423 to steam drum 471.
[0098] Stream 467, a saturated steam stream, can be then heated in the
convection section
414 of SMR 415 to produce a super-heated, high-pressure steam ("SH-HP") steam
stream 469,
which can be fed into a steam header and supplied to any suitable equipment or
process step.
For example, as shown and described above, a split stream 479 of stream 469
can be combined
with the sulfur-abated hydrocarbon feed stream 407 to form a combined stream
409, which is
then fed into the pre-reformer 441. For another example, a split stream 477 of
stream 469 can
be fed into a steam turbine 473, where it is expanded to produce an exhaust
steam stream 483
and shaft power. The shaft power can be transferred, via shaft 481, to any
suitable equipment
.. 475 to produce useful mechanical work_ One example of equipment 475 is an
electricity
generator, which converts the mechanical work into electrical energy
transmissible to any
suitable local or distant electrical equipment. Exhaust steam stream 483 can
have various
residual pressure and temperature suitable for, e.g., driving additional steam
turbines, heating
other equipment and/or streams, and the like. In a specific case the exhaust
steam stream 485
may be an LPS stream used to provide heat to the amine regenerator in a CO2
capture unit.
[0099] As shown in FIG. 4, the cooled reformed stream 425, comprising CO, Hz,
H2O, and
optionally CO2, is then fed into a first shift reactor 427. The first shift
reactor can be operated
under a first set of shifting conditions comprising the presence of a first
shift catalyst loaded
therein. Due to the relatively high temperature in the first set of shifting
conditions, the first
shift reactor 427 is sometimes called a high-temperature shift reactor. On
contacting the first
Date Recue/Date Received 2022-12-12
shift catalyst under the first set of shifting conditions, the forward
reaction of the following
preferentially occurs:
First Shift Catalyst
CO + H20 . CO2 + H2
(R-2)
[0100] Thus, a first shifted stream 429 comprising CO at a lower concentration
than stream
425 and CO2 at a higher concentration than stream 425 exits the first shift
reactor 427. Because
the forward reaction above is exothermic, stream 429 has a higher temperature
than stream 425
assuming the first shift reactor 427 is an adiabatic reactor.
[0101] The first shifted stream 429 can then be further cooled down at heat
exchanger 431
by any suitable stream having a temperature lower than stream 429. As shown in
FIG. 4, in a
preferred embodiment, a boiler feed water stream 434, supplied from a boiler
feed water
treatment unit 433, is used to cool down stream 429. The thus heated boiler
feed water stream
435 exiting the heat exchanger 431 can be supplied to steam drum 471 and at
least partly
supplied to the WHB 423, to produce high-pressure steam stream 467 as
described earlier, or
to any other suitable steam generator. Alternatively or additionally (not
shown), the
hydrocarbon feed stream 403, or a portion thereof, may be heated by stream 429
at heat
exchanger 431 or another heat exchanger upstream or downstream of heat
exchanger 431.
[0102] The cooled first shifted stream 436 exiting heat exchanger 431,
comprising CO, H2,
H20, and CO2, is then fed into a second shift reactor 437. The second shift
reactor can be
operated under a second set of shifting conditions comprising the presence of
a second shift
catalyst loaded therein and a temperature lower than in the first shift
reactor 427. Due to the
lower temperature, the second shift reactor 437 is sometimes called a low-
temperature shift
reactor. On contacting the second shift catalyst under the second set of
shifting conditions, the
forward reaction of the following preferentially occurs:
Second Shift Catalyst
CO + H20 . CO2 + H2 (R-3)
[0103] Thus, a second shifted stream 439 comprising CO at a lower
concentration than
stream 436 and CO2 at a higher concentration than stream 436 exits the second
shift reactor
437. Because the forward reaction above is exothermic, stream 439 has a higher
temperature
than stream 436 assuming the second shift reactor 437 is an adiabatic reactor.
[0104] The second shifted stream 439 can then be further cooled down at heat
exchanger 441
by any suitable stream having a temperature lower than stream 439. In a
preferred embodiment,
a boiler feed water stream (not shown) supplied from a boiler feed water
treatment unit (e.g.,
unit 433) can be advantageously used to cool down stream 439. The thus heated
boiler feed
36
Date Regue/Date Received 2022-12-12
water stream exiting the heat exchanger 441 can be supplied (not shown) to
steam drum 471
and at least partly supplied to the WHB 423, to produce high-pressure steam
stream 467 as
described earlier, or to any other suitable steam generator. Alternatively or
additionally (not
shown), the hydrocarbon feed stream 403, or a portion thereof, may be heated
by stream 439
at heat exchanger 441 or another heat exchanger upstream or downstream of heat
exchanger
441.
[0105] The cooled stream 443 exiting heat exchanger 441 can be further cooled
at heat
exchanger 445 by any suitable cooling medium having a lower temperature than
stream 443,
e.g., a cooling water stream, ambient air (using an air-fin cooler, e.g.), and
the like. Preferably,
a portion of the residual steam in stream 443 is condensed to liquid water in
stream 447, which
can be fed into a separator 449 to obtain a condensate stream 451 and a vapor
stream 453. The
steam-abated stream 453, a crude gas mixture, comprises primarily H2 and CO2,
and optionally
minor amount of residual CH4 and CO.
[0106] Stream 453 can then be supplied into a CO2 recovery unit 455 to produce
a CO2
stream 457 and an Hz-rich stream 459. Any suitable CO2 recovery unit known in
the art may
be used. A preferred CO2 recovery unit is an amine absorption and regeneration
unit, where
the crude gas mixture stream 453 contacts a counter-current stream of amine
which absorbs the
CO2, which is subsequently released from the amine upon heating
("regeneration"). The CO2
stream 457 can be supplied to a CO2 pipeline and conducted away. The CO2
stream 457 can be
compressed, liquefied, stored, sequestered, or utilized in manners known to
one skilled in the
art.
[0107] The Hz-rich stream 459 can advantageously comprise Hz at a molar
concentration
from, e.g., 80%, 81%, 82%, 83%, 84%, 85%, to 86%, 87%, 88%, 89%, 90%, to 91%,
92%,
93%, 94%, 95%, to 96%, 97%, 98%, 99%, based on the total moles of molecules in
stream 459.
In addition to Hz, stream 459 may comprise: (i) CH4 at a molar concentration
thereof based on
the total moles of molecules in stream 459, from, e.g., 0.1%, 0.3%, 0.5%,
0.8%, to 1%, 2%,
3%, 4%, or 5%; (ii) CO at a molar concentration thereof based on the total
moles of molecules
in stream 459, from, e.g., 0.1%, 0.3%, 0.5%, 0.8%, to 1%, 2%, or 3%; and (iii)
CO2 at a molar
concentration thereof based on the total moles of molecules in stream 459,
from, e.g., 0.1%,
0.2%, 0.3%, 0.4%, 0.5%, to 0.6%, 0.7%, 0.8%, 0.9%, or 1%. Stream 459 can be
advantageously used as a fuel gas for residential, office, and/or industrial
heating. Due to the
high concentration of H2 and low concentration of carbon-containing molecules
therein, the
combustion of stream 459 in the presence of an oxidant such as air, oxygen,
and the like, can
produce a flue gas stream comprising CO2 at a low concentration. In certain
embodiments, the
37
Date Regue/Date Received 2022-12-12
flue gas stream can comprises CO2 at a molar concentration based on the total
moles of H20
and CO2 in the flue gas stream of no greater than 20% (e.g., from 0.1%, 0.2%,
0.4%, 0.5%, to
0.6%, 0.8%, 1%, to 2%, 4%, 5%, to 6%, 8%, 10%, to 12%, 14%, 15%, to 16%, 18
mol%, or
20%). The flue gas stream can be advantageously exhausted into the atmosphere
without the
need to separate and capture CO2 therefrom.
[0108] In a preferred embodiment, as shown in FIG. 4, a split stream 417 of
stream 459 can
be supplied to the SMR 415, where it is combusted in burner(s) 418 to supply
thermal energy
to the SMR 415 heating the lower radiant section 416 and tube(s) 420b therein
and the
convection section 414 and tube 420a therein. Compared to the H2 production
plant shown in
FIG. 2, the flue gas stream 419 exiting the SMR 415 comprises CO2 at a
considerably lower
concentration, and therefore can be exhausted into the atmosphere with
considerably reduced
CO2 emission without the need to separate and capture CO2 therefrom.
FIG. 5
[0109] FIG. 5 schematically illustrates an inventive process/system 501 of
this disclosure
integrating a Hz-rich fuel gas production process/plant with an olefins
production plant
comprising a steam cracker. As shown, a natural gas stream 303 is combined
with a CH4-rich
stream 535 produced from the recovery section of an olefins production plant
and an HPS
stream 502 produced from a steam turbine (preferably a steam turbine driving a
process gas or
refrigeration compressor) 380 in the olefins production plant to form a joint
stream 307, which
is fed into a tube located in the convection section 309 of an SMR and heated
therein, and then
enters a tube containing a refoiming catalyst in the radiant section 311 of
the SMR. The SMR
receives a SMR fuel gas stream 516 (a Hz-rich fuel gas stream as described
below), which
combusts in the SMR to generate the thermal energy heating the radiant section
311 and the
convection section 309. On contacting the reforming catalyst, the CH4/steam
mixture
undergoes reforming reaction to produce a reformed gas stream 319 comprising
CO, CO2, H2,
and CH4 exiting the SMR. Stream 319 is then cooled down at waste-heat recovery
unit 321 to
obtain a cooled reformed stream 323 and an HPS stream (preferably a Super-HPS
stream) 301.
Stream 301 is then heated in the convection section of the SMR to obtain a
superheated HPS
("SH-HPS") (preferably a superheated Super-HPS) stream 343. Preferably stream
343 has a
pressure higher than the steam feed 502 to the SMR. As such, stream 343 or a
split stream is
not directly fed into the SMR, in contrast to the process of FIG. 3. Stream
343 is then supplied
into the olefins production plant, join other HPS stream(s) (preferably Super-
HPS stream(s))
produced in the olefins production plant such as stream(s) 375 produced from
steam cracker(s)
38
Date Regue/Date Received 2022-12-12
371 and stream(s) 365 produced from boiler(s) 363, to supply equipment,
particular steam
turbine(s) in the olefins production plant consuming such HPS, as described
below.
[0110] The cooled reformed stream 323 is then fed into a first, high-
temperature shift reactor
503, where it contacts a first shift catalyst to effect the conversion of a
quantity of CO/H20 into
CO2 and H2 to produce a first shifted stream 505 exiting the first shift
reactor 503. Stream 505
is then cooled down at heat exchanger(s) (now shown) before entering a second,
low-
temperature shift reactor 507 to produce a second shifted stream 509. Stream
509 is then cooled
down at heat exchanger(s) 511 to produce a cooled second shifted stream 513
containing
condensed water. In water separator 515, a condensed water stream 517 is
separated from
stream 513 to produce a steam-abated stream 519 comprising primarily Hz, CO2,
and minor
amounts of CO and C114. Stream 519, preferably at a pressure similar to
streams 509 and 513
(higher than 200 kPa, preferably at least 700 kPa, preferably at least 1,000
kPa), is then fed into
an amine CO2 absorption/regeneration unit 521 to produce a CO2 stream 523 and
an Hz-rich
stream 524 (similar to stream 459 in FIG. 4). CO2 stream 523 can be
compressed, liquefied,
conducted away, stored, sequestered, or utilized, reducing CO2 emissions to
the atmosphere.
[0111] Stream 524, comprising CO, CO2, and H2, can be combined with a steam
cracker H2
stream 525 produced from the recovery section of the olefins production plant
as described
below to form a joint fuel gas stream 527. A split stream 516 of stream 527 is
supplied to and
combusted in the SMR to generate the thermal energy heating the radiant
section 311 and the
convection section 309 as described above. Flue gas stream 518 exiting the SMR
contains
considerably reduced concentration of CO2 compared to the SMR flue gas stream
357 in the
process of FIG. 3. As such, CO2 capture from stream 518 is not needed, in
contrast to the
process of FIG. 3.
[0112] As shown in FIG. 5, a split stream 531 of the Hz-rich fuel gas stream
527 is then
supplied to steam cracker(s) 371 located in an olefins production plant as a
steam cracker fuel,
where it combusts to provide the thermal energy needed for the heating and
cracking of a steam
cracker feed and to generate a flue gas stream 533 exiting the steam cracker
371. Due to the
limited amount of CO and CH4 present in stream 527, the flue gas stream 533
comprises limited
amount of CO2, rendering CO2 capture from it unnecessary. A steam cracker
hydrocarbon feed
stream 369 and a dilution steam stream 373 enter steam cracker 371, heated in
a convection
section thereof, and then enter into a radiant section where cracking occurs
at high temperature
for a short residence time to produce a steam cracker effluent comprising H2,
Cl-C4
hydrocarbons comprising the desirable C2-C4 olefins, and C5+ hydrocarbons,
among others.
The steam cracker effluent is immediately cooled down via quenching and/or
indirect heat
39
Date Regue/Date Received 2022-12-12
exchange in steam cracker 371, producing a quenched steam cracker effluent
stream 375 and a
substantial quantity of HPS which is then superheated to produce an SH-HPS
stream 376. The
quenched steam cracker effluent stream 375 is sent to the hot-ends 378 of the
recovery section
where it is further cooled. In section 378 a dilution steam 373 is generated
which is sent to
steam cracker 371. A split stream 529 of Hz-rich stream 527 may be supplied to
one or more
boilers 363 to produce additional amount of SH-HPS in stream 365. Streams 343,
365 and 376
can be combined to form a joint stream 377. Separation of the cooled steam
cracker effluent
stream produces a process gas stream comprising H2 and Cl-C4 hydrocarbons
including the
desired C2-C4 olefins. The process gas stream is compressed in one or more
compressors 380
to an elevated pressure, supplied to the cold end 379 of the recovery section
to produce, among
others, a steam cracker Hz stream 525 described above, a C114-rich stream 525
consisting
essentially of CH4 and H2; an ethylene product stream 391, a propylene product
stream 392,
and one or more C4+ co-product streams 393, among others.
[0113] The SH-HPS stream 377 is supplied to one or more steam turbine(s)
driving one or
more process gas and/or refrigeration compressors 380. An HPS stream 381 may
be produced
from one or more turbine(s). A split stream 502 of stream 381 can be fed into
the SMR together
with the natural gas feed stream 303 and the CH4-rich stream 535 as described
above. Another
split stream of stream 381 may be fed to one or more other turbine(s), where
it is expanded to
produce additional shaft power, or may be used for process heating duty. An
MPS stream 383
may be produced from one or more turbine(s), split into a stream 386 which is
fed to one or
more other turbine(s), o may be used for process heating duty, and a stream
385 which is fed
to the hot end 378 of the recovery section to generate dilution steam. An LPS
stream 382 may
be produced from one or more turbine. As shown in FIG. 5, a split stream (or
the entirety) of
stream 382 can be supplied to the amine CO2 absorption/regeneration unit 521,
where it is used
to heat the regenerator to effect the separation of CO2 stream 523 from an
amine. The turbines
may optionally exhaust one or more condensable streams 584, which is supplied
to one or more
surface condensers 587, where it is cooled by a cooling water stream 588 to
produce a
condensate stream 589.
[0114] In process 501 of FIG. 5, CO2 emissions from steam cracker(s) 371 is
reduced by
combusting the Hz-rich stream 367 compared to conventional steam cracker(s)
combusting
natural gas, methane-rich tail-gas, or a combination of natural-gas and
methane-rich tail-gas;
CO2 emissions from boiler(s) 363 is reduced because Hz-rich stream 529 is
supplied thereto,
compared to conventional boilers combusting natural gas or a combination of
natural-gas and
methane-rich-tail-gas; and CO2 emission is reduced by capturing CO2 stream 523
from the
Date Regue/Date Received 2022-12-12
SMR flue gas stream 357 using the amine absorption/regeneration unit 355
compared to a
conventional H2 production plant using an SMR combusting natural gas without
capturing CO2
from the SMR flue gas. Compared to process/system 301 of FIG. 3, the
integrated
process/system 501 of FIG. 5 has at least the following advantages: (i) lower
capital costs and
operational costs due to the elimination of the PSA unit; (ii) because the
amine CO2 capture
unit 521 in FIG. 5 operates at an above-atmospheric pressure (e.g., 200
kPa absolute,
preferably 500 kPa absolute, preferably 800
kPa absolute) considerably higher than the
amine unit 355 in the process of FIG. 3 (which operates at atmospheric
pressure), unit 521 can
be considerably smaller than unit 355, resulting in considerably less capital
and operational
costs; (iii) because the CH4-rich stream 535 is fed into the SMR as a part of
the hydrocarbon
feed, it is converted into a portion of the Hz-rich stream 522 and a portion
of the CO2 stream
523 which can be captured, resulting in potentially considerably lower CO2
emission to the
atmosphere than the process of FIG. 3, where the tailgas stream 390, rich in
C114, is typically
combusted to produce a flue gas comprising CO2 at atmospheric pressure
difficult and
expensive to capture; (iv) because the HIPS stream 343 in FIG. 5 is supplied
to the olefins
production plant feeding the steam turbines including the major turbines
therein, the power
island including steam turbine 347 and generator 351 in FIG. 3 is eliminated,
resulting in
considerably lower capital and operational costs; (v) because LPS stream(s)
produced from
various turbines in the olefins production plant in FIG. 5 are supplied to the
amine CO2 capture
unit 521, a reduced number of streams and/or reduced total quantity of
condensable stream(s)
584 can be supplied to fewer and/or reduced-duty surface condenser(s) 587
compared to
condensable stream(s) 384 and surface condenser(s) 387 in FIG. 3, or
condensable streams 584
and surface condensers 587 may be completely eliminated, resulting in reduced
amount of
thermal energy released to the atmosphere, and in considerably lower capital
and operational
costs.
FIG. 6 (Comparative)
[0115] FIG. 6 schematically illustrates a steam supply/consumption
configuration 601 of a
comparative olefins production plant including multiple steam crackers. As
shown, the plant
supplies superheated steams through lines 603, 605, 607, and 609 at the
following temperature
and pressures, respectively: 930 F and 1500 psig (Super-HPS); 700 F and 660
psig (HPS);
570 F and 225 psig (MPS); and 450 F and 50 psig (LPS). 1560 kilo-pounds/hour
("klb/hr")
of Super-HPS in stream 617 produced by a gas turbine generator unit 611, 540
klb/hr of Super-
HPS in stream 619 produced by the multiple steam cracker furnaces 613, and 596
klb/hr of
Super-HPS in stream 621 produced by boilers 615 are supplied to line 603. From
line 603, the
41
Date Regue/Date Received 2022-12-12
Super-HPS streams 625, 627, 629, 631, and 633 are supplied to steam turbines
635, 637, 639,
641, and heat exchanger 643 at the following flow rates, respectively: 879
klb/hr; 710 klb/hr,
745 klb/hr, 301 klb/hr, and 3 klb/hr. From line 603, 58 klb/hr of the Super-
HPS is exported to
other users 623. Steam streams entering steam turbines are expanded therein to
produce one or
more steam streams and shaft power. The shaft power can be used to drive
various equipment
in the olefins production plant, such as process gas compressor(s), propylene
refrigeration
compressor(s), and pumps, and the like.
[0116] Line 605 receives an imported HPS stream 604 at 30 klb/hr, an HPS
stream 645
produced from steam turbine 635 at 700 klb/hr, an HPS stream 649 produced from
steam
turbine 637 at 585 klb/hr, an HPS stream 657 produced from steam turbine 641
at 100 klb/hr,
an HPS stream 667 from heat exchanger 643 at 3 klb/hr, and an HPS stream 665
from a steam
drum 663 at 10 klb/hr. All four steam turbines 635, 637, 639, and 641 also
produce a
condensable steam stream condensed at a surface condenser 647, 651, 655, and
661,
respectively, at the following flow rates, respectively: 179 klb/hr, 124
klb/hr, 79 klb/hr, and
149 klb/hr. From line 605, HPS streams 671, 673, and 620 are supplied to steam
turbines 675
and 677 and other on-site users 622 at the following flow rates, respectively:
540 klb/hr, 127
klb/hr, and 68 klb/hr. From line 605, 695 klb/hr of HPS is exported to other
users 669.
[0117] Line 607 receives an MPS stream 679 produced from back-pressure steam
turbines
675 at 540 klb/hr, and an MPS stream 653 produced from steam turbine 639 at
667 klb/hr.
Steam turbines 675 does not produce a condensable stream supplied to a surface
condenser.
From line 607, MPS streams 685, 687 and 630 are supplied to steam turbines
689, on-site users
693, and on-site users 632 at the following flow rates, respectively: 324
klb/hr, 206 klb/hr, and
306 klb/hr. From line 607, 330 klb/hr of MPS is exported to other users 683.
[0118] Line 609 receives an imported LPS stream 610 at a flow rate of 12
klb/hr, an LPS
stream 691 produced from back-pressure steam turbines 689 at 324 klb/hr, an
LPS stream 681
produced from steam back-pressure turbines 677 at 127 klb/hr, an LPS stream
695 produced
from steam drum 697 at a flow rate of 70 klb/hr, and an LPS stream 659 from
turbines 541 at
52 klb/hr. Neither of steam turbines 689 and 677 produces a condensable stream
supplied to a
surface condenser. From line 609, LPS streams 640 and 650 are supplied to on-
site users 642
and 652, respectively, at the following flow rates, respectively: 261 klb/hr,
and 207 klb/hr. No
LPS is exported to external user 699.
FIG. 7 (Inventive)
[0119] FIG. 7 schematically illustrates an inventive steam supply/consumption
configuration
701 of an olefins production plant modified from the plant of FIG. 6 and steam-
integrated with
42
Date Regue/Date Received 2022-12-12
an SMR. As shown in FIG. 7, the plant supplies superheated steams through
lines 603, 605,
607, and 609 at the following temperature and pressures, respectively: 930 F
and 1500 psig
(Super-HPS); 700 F and 660 psig (HPS); 570 F and 225 psig (MPS); and 450 F
and 50 psig
(LPS), the same as in FIG. 6. 1560 klb/hr of Super-HPS in stream 617 produced
by a gas
turbine generator unit 611, 540 klb/hr of Super-HPS in stream 619 produced by
the multiple
steam cracker furnaces 613, 262 klb/hr of Super-HPS in stream 721 produced by
boilers 715,
and 905 klb/hr of Super-HPS in stream 704 produced by an SMR 703 are supplied
to line 603.
From line 603, the Super-HPS streams 725, 727, 729, 731, and 633 are supplied
to steam
turbines 635, 637, 639, 641, and heat exchanger 643 at the following rates,
respectively: 951
klb/hr; 808 klb/hr, 1073 klb/hr, 373 klb/hr, and 3 klb/hr. From line 603,58
klb/hr of the Super-
HPS is exported to other users 623.
[0120] Line 605 receives an imported HPS stream 604 at 30 klb/hr, an HPS
stream 745
produced from steam turbine 635 at 630 klb/hr, an HPS stream 749 produced from
steam
turbine 637 at 700 klb/hr, an HPS stream 753 produced from steam turbine 639
at 407 klb/hr,
an HPS stream 757 produced from steam turbine 641 at 149 klb/hr, an HPS stream
667 from
heat exchanger 643 at 3 klb/hr, and an HPS stream 665 from a steam drum 663 at
10 klb/hr.
Only steam turbines 637 and 641 also produce a condensable steam stream
condensed at a
surface condenser 751 and 761, respectively, at the following flow rates,
respectively: 108
klb/hr and 89 klb/hr. From line 605, HPS streams 671 and 673 are supplied to
steam turbines
675 and 677 and other on-site users 622 at the following flow rates,
respectively: 540 klb/hr,
127 klb/hr, and 68 klb/hr. From line 605, 695 klb/hr of HPS is exported to
other users 669.
Additionally, from line 605, an HPS stream 705 at a flow rate of 499 klb/hr is
supplied to SMR
703 as steam feed to the SMR.
[0121] Line 607 receives an MPS stream 679 produced from steam turbine 675 at
540 klb/hr,
and an MPS stream 755 produced from steam turbine 639 at 666 klb/hr. Steam
turbine 675
does not produce a condensable stream supplied to a surface condenser. From
line 607, MPS
streams 685, 687 and 630 are supplied to steam turbine 689, on-site users 693,
and on-site users
632 at the following flow rates, respectively: 324 klb/hr, 206 klb/hr, and 306
klb/hr. From line
607, 360 klb/hr of MPS is exported to other users 683.
.. [0122] Line 609 receives an imported LPS stream 610 at a flow rate of 12
klb/hr, an LPS
stream 691 produced from steam turbine 689 at 324 klb/hr, an LPS stream 681
produced from
steam turbine 677 at 127 klb/hr, an LPS stream 695 produced from steam drum
697 at a flow
rate of 70 klb/hr, and an LPS stream 759 produced from steam turbine 641 at
136 klb/hr.
Neither of steam turbines 689 and 677 produces a condensable stream supplied
to a surface
43
Date Regue/Date Received 2022-12-12
condenser. From line 609, LPS streams 640 and 650 are supplied to on-site
users 642 and 652,
respectively, at the following flow rates, respectively: 261 klb/hr, and 207
klb/hr. Additionally,
from line 609, an LPS stream 707 at a flow rate of 487 klb/hr is supplied to
the amine
regenerator of an amine CO2 capture unit associated with SMR 703.
[0123] This disclosure is further illustrated by the following non-limiting
Examples.
Examples
[0124] The olefins production plants illustrated in FIGs. 6 and 7 are used in
these examples.
Example 1, a comparative example, corresponds to FIG. 6. Example 2 corresponds
to a
combination of the olefins production plant of FIG. 6 and a Hz-rich fuel gas
production plant
of FIG. 4 wherein the Hz-rich stream 461 is supplied to the steam crackers 613
as steam cracker
fuel; and a tailgas stream (similar to stream 390 in FIG. 3) produced in the
olefins production
plant is fed to the pre-reformer 411 in FIG. 4 as a hydrocarbon feed to the
SMR. Example 3
corresponds to an Hz-rich fuel gas production plant steam-integrated with the
olefins
production plant as shown in FIGs. 5 and 7. The process conditions in the
olefins plant, and
hence the olefins plant compressor power requirements are assumed to remain
constant in all
three examples. In all three examples, the olefins production plant has the
same steam crackers
613 with a 2,240 MBtu/hr total firing rate; and (ii) the same gas turbine
generator unit 611
generating 1560 klb/hr of Super-HPS in stream 617, while supplying electricity
to the olefins
production plant and beyond. In all these examples, steam turbine 635 drives a
low-pressure
process gas compressor, steam turbine 637 drives a high-pressure process gas
compressor, and
steam turbines 639 and 641 drive propylene refrigeration compressors. Import
steam streams
604 and 610, streams 665, 633, 667, 620, 630, 640, 650, 671, 673, 685, 691,
687, 695, and
export streams supplied to users 623, 669, 683, and 699 remain constant in all
three examples.
Example 1 (Comparative)
[0125] Example 1 corresponds to FIG. 6. It is assumed the fuel gases supplied
to the steam
crackers 613 and boilers 615 both comprise, on average, 35 mol% of Hz and 65
mol% of CH4,
based on the total moles of molecules in the fuel gases. The boilers 615 have
a 1,990 MBtu/hr
total firing rate. Thus, the estimated CO2 emissions from the steam cracker
furnaces and the
boilers are 1,780 kilotons per year ("kta"). From the four major steam-
turbines 635, 637, 639,
and 641, a total of 530 klb/hr of steam is condensed, giving a total condenser
duty of 520
MBtu/hr (152MW).
Example 2
[0126] Example 2 corresponds to a combination of the olefins production plant
of FIG. 6 and
an Hz-rich fuel gas production plant of FIG. 4 wherein the Hz-rich stream 461
is supplied to
44
Date Regue/Date Received 2022-12-12
the steam crackers 613 as steam cracker fuel; and a tailgas stream (similar to
stream 390 in FIG.
3) produced in the olefins production plant is fed to the pre-refoliner 411 in
FIG. 4 as a
hydrocarbon feed to the SMR. No steam integration between the Hz-rich fuel gas
production
plant and the olefins production plant is contemplated in this Example 2. The
reformer waste-
heat recovery system generates HPS stream 469, some of which (split stream
479) is consumed
in the SMR. The remainder (split stream 477) passes through a steam-turbine-
generator (STG)
generating 21 MW of electrical power. The STG is a back-pressure LPS turbine,
and the
exhaust LPS stream 485 is used to regenerate the amine used in the amine CO2
unit 455. Fuel-
grade Hz-rich stream 461 is combusted in the steam crackers 613 and boilers
615 in the olefins
production plant. Stream 459, 461, and 417 are assumed to comprise 85 mol% Hz
and 15 mol%
CH4. Stream 461 exported to the olefins plant has a contained H2 content of
185 million
standard cubic feet per day ("IvIMSC/D").
[0127] In this Example 2, the total CO2 emissions from the steam crackers 613,
the boilers
615, and the SMR are 969 kta, a reduction of 811 kta from Example 1. If the
electricity
generated in the STG (generator 475 in FIG. 4) is credited at a CO2 intensity
of 0.389 ton per
MWh, the net CO2 emissions from the steam crackers 613, boilers 615, and the
Hz-rich fuel
gas plant 900 kta, which is a reduction of 880 kta (49%), from Example 1.
Total fuel fired in
the steam crackers 613, boilers 615 and the SMR increases from 4,230 MBtu/hr
to 5,930
MBtu/hr, an increase of 40%.
[0128] Total CO2 in CO2 stream 457, which can be sequestered, is 1,410 kta,
giving a ratio
of CO2 sequestered/CO2 avoided of 1.60.
Example 3
[0129] Example 3 corresponds to an Hz-rich fuel gas production plant steam-
integrated with
the olefins production plant as shown in FIG. 7. Example 3 also corresponds to
FIG. 5. A
substantially the same Hz-rich fuel gas plant used in Example 2 above is used
in this Example
3, providing 185 MMSCF/D contained Hz in Hz-rich stream 461 in FIG. 4 (or
stream 524 in
FIG. 5), which is supplied to the SMR and the olefins production plant for
combustion in the
steam crackers 613 (or 371 in FIG. 5) and boilers 615 (or 363 in FIG. 5). A
CH4-fich stream
535 produced from the olefins production plant is supplied to the SMR as a
portion of the
hydrocarbon feed. The refoimer waste-heat recovery unit ("WHRU") generates
Super-HP
steam stream 704 (or stream 343 in FIG. 5) at 905 klb/hr, which is entirely
exported to the
olefins plant Super-HPS line 603. The HPS steam 705 required by the SMR is
supplied from
the olefin plant HP steam header in line 605.
Date Regue/Date Received 2022-12-12
[0130] Compared to Example 1, two major steam turbines are changed to provide
the desired
steam system integration. Turbine 635, the low-pressure process gas compressor
turbine, is
changed from an HPS-extraction-and-condensing turbine to an HPS-extracti on-
and-LPS-
back-pressure turbine. This reduces condensing energy loss to atmosphere and
provides LPS
stream 747 for the amine regenerator in the CO2 capture unit 455. Turbine 639,
the propylene
refrigeration compressor turbine, is changed from an MPS-extraction-and-
condensing turbine
to an HPS-extraction-and-MPS- back-pressure turbine. This reduces condensing
energy loss to
the atmosphere and provides HPS stream 705 for the SMR 703. Turbine 637, the
high-pressure
process gas compressor turbine and turbine 641, the propylene concentrator
heat-pump turbine,
remain HPS-extraction-and-condensing turbines, but with increased rates of HPS
stream 749
and 757, and reduced rates of condensable steam condensed at surface
condensers 751 and 761.
This also reduces condensing energy loss to the atmosphere and provides HPS
steam 705 for
SMR 703.
[0131] Compared to Examples 1 and 2, in Example 3, the required firing rates
for boilers 715
are reduced from 1,990 MBtu/hr to 1,250 MBtu/hr, a reduction of 740 MBtu/hr
(37%). Since
the same volume of Hz-rich fuel-gas is imported from the SMR, the hydrogen
content in the
fuel-gas fired in the cracking furnaces and boilers increases from 85 mol% in
Example 2 to 91
mol% in this Example 3 due to less make-up natural-gas being required.
[0132] In this Example 3, the total CO2 emissions from the steam crackers 613,
the boilers
615, and the SMR stacks is 610 kta, a reduction of 1170 kta (66%) from Example
1, and a
reduction of 290 kta (32%) from Example 2. Since there is no STG in the
refoinier/hydrogen
plant, there is no electricity credit versus Example 1. Compared to Example 2,
the ratio of CO2
sequestered/CO2 avoided in this Example 3 is reduced from 1.60 to 1.21 due to
the increased
energy efficiency of the integrated system. Moreover, in this Example 3,
condenser energy
losses to atmosphere are reduced from 520 MBtu/hr to 190 MBtu/hr, a saving of
330 MBtu/hr
(63%) compared to Examples 1 and 2. Key perfoimance parameters are further
provided/compared in TABLE II, below:
TABLE II
Change between
Example
Example
1 2 3 2-1 3-1 3-2
Cracking Furnace Firing MBtu/hr 2,240 2,240 2,240 0 0 0
Boiler Firing MBtu/hr 1,990 1,990 1,250 0 -740
-740
Reformer Firing MBtuihr 0 1,700 1,700 1,700 1,700 0
46
Date Regue/Date Received 2022-12-12
Total Firing
MBtu/hr 4,230 5,930 5,190 1,700 -740 -740
H2 content of Fuel-gas mol% 35 85 91 50 56 6
Stack CO2 (8400 hrs/yr) kta 1,780 969 610 -811
-1170 -359
STG electricity MW 21 21 -21
STG CO2 Equiv (0.389 t/MWh) kta 69 69 -69
Net CO2 Emissions (8400 hrs/yr) kta 1,780 900 610 -880
-1170 -290
CO2 Avoided (vs. Example 1) kta 880 1,170 -
49 66
Ida -880 0 290
CO2 Avoided (vs. Example 2)
0 16
Turbine Condenser Duty MBtu/hr 520 520 190
0 -330 -330
CO2 Sequestered kta - 1,410 1,410 1,410 1,410 0
CO2 sequestered/avoided
1.60 1.21
(v. Example 1)
Listing of Embodiments
[0133] This disclosure can additionally include one or more of the following
non-limiting
embodiments:
[0134] Al. A process comprising:
(I) supplying a hydrocarbon feed and a steam feed into a syngas producing unit
comprising a reforming reactor under syngas producing conditions to produce a
reformed
stream exiting the reforming reactor, wherein the syngas producing conditions
include the
presence of a reforming catalyst, and the reformed stream comprises H2, CO,
and steam;
(II) cooling the refoimed stream by using a waste heat recovery unit ("WHRU")
to
produce a cooled reformed stream and to generate a high-pressure steam ("HPS")
stream;
(III) contacting the cooled reformed stream with a first shifting catalyst in
a first shift
reactor under a first set of shifting conditions to produce a first shifted
stream exiting the first
shift reactor, wherein the first shifted stream has a lower CO concentration
and a higher CO2
concentration than the cooled refomied stream;
(IV) cooling the first shifted stream to obtain a cooled first shifted stream;
(V) contacting the cooled first shifted steam with a second shifting catalyst
in a second
shift reactor under a second set of shifting conditions to produce a second
shifted stream exiting
the second shift reactor, wherein the second shifted stream has a lower CO
concentration and
a higher CO2 concentration than the cooled first shifted stream;
(VI) abating steam present in the second shifted stream to produce a crude gas
mixture
stream comprising CO2 and Hz;
47
Date Regue/Date Received 2022-12-12
(VII) recovering at least a portion of the CO2 present in the crude gas
mixture stream
to produce a CO2 stream and a Hz-rich stream, wherein the Hz-rich stream
comprises H2 at a
concentration of at least 80 mol%, based on the total moles of molecules in
the Hz-rich stream;
and
(VIII) supplying a portion of the Hz-rich stream to an olefins production
plant
comprising a steam cracker as at least a portion of a steam cracker fuel gas,
and combusting
the steam cracker fuel gas to provide thermal energy to the steam cracker.
[0135] A2. The process of Al, wherein the Hz-rich stream further comprises H2
at a
concentration of at least 85 mol% and at least one and preferably all of: < 5
mol% of CH4; < 3
mol% CO; and < 1 mol% CO2, based on the total moles of molecules in the Hz-
rich stream.
[0136] A3. The process of Al or A2, further comprising:
(IX) producing a CH4-rich stream from the steam cracker effluent; and
(X) providing at a portion of the CH4-rich stream as at least a portion of the
hydrocarbon
feed.
[0137] A4. The process of A3, wherein the CH4-rich stream comprises at least
one of: < 40
mol% Hz; < 10 mol% ethane; and < 5 mol% CO, based on the total moles of
molecules in the
CH4-rich stream.
[0138] A5. The process of A3 or A4, wherein the CH4-rich stream has an
absolute pressure
higher than that of the hydrocarbon feed supplied into the syngas producing
unit in step (I), and
step (X) comprises:
(Xa) expanding the CH4-rich stream through a turbo-expander and/or a Joule-
Thompson valve to produce a cooled CH4-rich stream having a pressure in the
vicinity of the
pressure of the hydrocarbon feed;
(Xb) heating the cooled CH4-rich stream by using a stream in the olefins
production
plant via a heat exchanger to produce a heated CH4-rich stream; and
(Xc) providing at least a portion of the heated CH4-rich stream as at least a
portion of
the hydrocarbon feed.
[0139] A6. The process of any of Al to AS, further comprising:
(XI) producing a steam cracker Hz stream from the olefins production plant;
and
(XII) supplying at least one of the following to the syngas producing unit as
at least a
portion of the reforming fuel gas: (a) at least a portion of the Hz-rich
stream; (b) at least a
portion of the steam cracker H2 stream; and (c) a joint stream of (a) and (b).
[0140] A7. The process of any of Al to A6, further comprising:
48
Date Regue/Date Received 2022-12-12
(XIII) supplying at least one of the following to the steam cracker as at
least a portion
of the steam cracker fuel gas: (a) a least a portion of the steam cracker H2
stream; (b) at least a
portion of the steam cracker H2 stream; and (c) a joint stream of (a) and (b).
[0141] A8. The process of any of Al to A7, further comprising:
(XIV) supplying at least one of the following to boiler(s) located in the
olefins
production plant as a boiler fuel gas: (a) a least a portion of the steam
cracker H2 stream; (b) at
least a portion of the steam cracker H2 stream; and (c) a joint stream of (a)
and (b); and
combusting het boiler fuel gas to supply thermal energy to the boiler(s).
[0142] A9. The process of A8, wherein the boiler(s), taken together, produce
no more than
10% of the total amount of HPS streams consumed by the olefins production
plant.
[0143] A10. The process of any of Al to A7, wherein the olefins production
plant does not
include a boiler producing steam consumed by the olefins production plant.
[0144] All. The process of any of A6 to A10, wherein the Hz-rich stream and
the steam
cracker H2 stream, taken together, provide at least 60% of total fuel gas
required, on a Btu basis,
by the olefins production plant.
[0145] Al2. The process of claim All, wherein the Hz-rich stream provides at
least 60% of
total fuel gas required, on a Btu basis, by the operation of the olefins
production plant.
[0146] A13. The process of any of Al to Al2, wherein the HPS stream generated
in step (II)
has an absolute pressure from 4,000 kPa to 14,000 kPa, and the process further
comprises:
(XV) heating the HPS stream to produce a superheated HPS ("SH-HPS") stream
having
a temperature from 350 C to 550 C; and
(XVI) supplying at least a portion of the SH-HPS stream to at least one first
steam
turbine(s) in the olefins production plant, and expanding the SH-HPS stream in
the at least one
first steam turbine(s) to produce shaft power and a first expanded steam
stream.
[0147] A14. The process of A13, wherein in step (XVI), the portion of the SH-
HPS stream
is combined with an SH-HPS produced from the steam cracker to form a joint SH-
HPS stream,
and at least a portion of the joint SH-HPS stream is then supplied to the
first turbine.
[0148] A15. The process of A13 or A14, wherein the at least one first steam
turbine(s) drives
at least one of the following in the olefins production plant: a process gas
compressor; a
propylene refrigeration compressor; an ethylene refrigeration compressor; and
combinations
thereof.
[0149] A16. The process of any of A13, A14, and A15, wherein the first
expanded stream
has a pressure in the vicinity of that of the steam feed to the syngas
producing unit, and the
process further comprises:
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Date Regue/Date Received 2022-12-12
supplying at least a portion of the first expanded steam stream to the syngas
producing
unit as at least a portion of the steam feed.
[0150] A17. The process of any of A13 to A16, further comprising:
(XVII) expanding at least a portion of the first expanded steam stream in a
second steam
turbine in the olefins production plant to produce additional shaft power and
a second expanded
steam stream.
[0151] A18. The process of any of A13 to A17, further comprising:
(XVIII) expanding at least a portion of the second expanded steam stream in a
third
steam turbine in the olefins production plant to produce additional shaft
power and a third
expanded steam stream.
[0152] A19. The process of any of A13 to A18, wherein the SH-HPS stream
obtained in step
(XVI) is a Super-HPS stream, and the first expanded stream is an HPS stream,
an MPS stream,
or an LPS stream.
[0153] A20. The process of any of A17 to A19, wherein the second expanded
steam is an
MPS stream, or an LPS stream.
[0154] A21. The process of any of A17 to A20, wherein the third expanded
stream is an LPS
stream.
[0155] A22. The process of any of A13 to A21, wherein at least one of the
first steam turbine,
the second steam turbine, and the third steam turbine does not produce a
condensable stream
supplied to a surface condenser.
[0156] A23. The process of any of A13 to A22, wherein step (VII) is carried
out using an
amine CO2 capture unit comprising an amine regenerator, and the process
further comprises:
(XIX) extracting a process heating steam stream from at least one of the first
steam
turbine, the second steam turbine, and the third steam turbine, and the
process heating steam
stream has an absolute pressure from 200 kPa to 1,050 kPa; and
POO supplying the process heating steam stream to the amine regenerator to
effect the
separation of the CO2 stream from the Hz-rich stream.
[0157] A24. The process of any of Al to A23, wherein the olefins production
plant
comprises a combined-cycle power plant, the combined-cycle power plant
comprises one or
more duct burners combusting a duct burner fuel to generate thermal energy,
and the process
further comprises combusting a portion of the Hz-rich stream and/or a portion
of the steam-
cracker H2 stream as at least a portion of the duct burner fuel.
Date Regue/Date Received 2022-12-12
[0158] A25. The process of any of Al to A24, wherein any portion of the HPS
stream and
any steam generated in the olefins production plant is not supplied to a steam
turbine driving
an electricity generator.
[0159] A26. The process of any of A27 to A25, wherein the Hz-rich stream and
the steam-
cracker H2 stream together provides at least 60%, on a BTU basis, of the total
combustion fuel
needed by the operation of the olefins production plant.
[0160] A27. The process of any of Al to A26, wherein a single water
demineralization plant
provides all the water needed for steam generating in the Hz-rich gas
production plant and the
olefins production plant.
[0161] A28. The process of any of Al to A27, wherein the refoimed stream has
at least one
of the following: a temperature of from 750 C to 1,200 C, and an absolute
pressure from 700
kPa to 5000 kPa.
[0162] A29. The process of any of Al to A28, wherein the cooled reformed
stream produced
in step (II) has a temperature from 285 C to 400 C.
[0163] A30. The process of any of Al to A29, wherein in step (III), the first
shifted stream
has at least one of the following: a temperature from 335 C to 500 C; and an
absolute pressure
from 700 kPa to 5,000 kPa.
[0164] A31. The process of any of Al to A30, wherein step (IV) comprises
cooling the first
shifted stream, via a heat exchanger, by a cooling stream selected from: a
stream comprising
the hydrocarbon feed; a boiler feed water stream; and combinations thereof.
[0165] A32. The process of any of Al to a31, wherein the cooled first shifted
stream has at
least one of the following: a temperature from 150 C to 250 C, and an
absolute pressure from
700 kPa to 5,000 kPa.
[0166] A33. The process of any of Al to A32, wherein in step (V), the second
shifted stream
has at least one of the following: a temperature from 150 C to 300 C; an
absolute pressure
from 700 kPa to 5000 kPa; and a CO concentration no greater than 5.0 mol%,
based on the
total moles of molecules in the second shifted stream.
[0167] A34. The process of any of Al to A33, wherein step (VI) comprises:
(Via) cooling the second shifted stream to condense a portion of steam in the
second
shifted stream to form liquid water and to obtain a cooled second shifted
stream; and
(Vlb) separate the liquid water from the cooled second shifted stream to
obtain the
crude gas mixture stream.
[0168] A35. The process of any of the preceding claims, wherein step (VII)
comprises at
least one of the following:
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Date Regue/Date Received 2022-12-12
(VII.1) separating at least a portion of the gas mixture by using an amine
absorption
and regeneration process;
(VII.2) separating at least a portion of the gas mixture by using a cryogenic
CO2
separation process;
(VII.3) separating at least a portion of the gas mixture by using a membrane
separation
process; and
(VII.4) separating at least a portion of the gas mixture by using a physical
absorption
and regeneration process.
[0169] A36. The process of any of Al to A35, wherein step (VII) comprises the
following:
(Villa) obtaining an exhaust steam stream having an absolute pressure from 200
kPa to
1,050 kPa and shaft power from one or more extraction turbine(s)extraction
turbine(s) and/or
back-pressure turbine(s) (preferably one or more back-pressure turbine(s))
located in a an
olefins production plant;
(VIIb) feeding the crude gas mixture stream and a lean-amine stream comprising
an
amine into an absorption column;
(VIlc) obtaining a CO2-rich amine stream and a CO2-depleted residual gas
stream from
the absorption column;
(VIId) feeding at least a portion of the CO2-rich amine stream into a
separation column;
(Vile) heating the at least a portion of the CO2-rich amine stream in the
separation
column using an exhaust steam stream to produce an overhead stream rich in CO2
and a bottoms
stream rich in the amine; and
(Vhf) recycling at least a portion of the bottoms stream to the absorption
column as at
least a portion of the lean-amine stream.
[0170] A37. The process of any of Al to a36, wherein the syngas producing unit
comprises
a steam-methane-reformer ("SMR") and/or an autothermal reformer ("AIR").
[0171] A38. The process of A37, wherein:
the syngas producing unit comprises a SMR;
the SMR comprises: one or more SMR burners where an SMR fuel combusts to
supply
thermal energy to the SMR; a radiant section heated by the thermal energy in
which the
hydrocarbon feed and steam react under the syngas producing conditions; a
convection section
heated by the thermal energy in which the hydrocarbon feed and steam are
preheated before
entering the radiant section; and
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Date Regue/Date Received 2022-12-12
in step (VII), a portion of the H2-rich stream and/or a portion of the steam
cracker H2
stream is supplied to the plurality of SMR burners as at least a portion of
the reforming fuel
gas.
[0172] A39. The process of A38, wherein step (XV) is carried out, and in step
(XV), the HPS
stream is heated in the convection section of the SMR and/or an auxiliary
furnace to obtain the
SH-HPS stream.
[0173] A40. The process of A37, wherein:
the syngas producing unit comprises an ATR;
an 02 stream is fed into the ATR;
the ATR comprises a reaction vessel into which the hydrocarbon feed, the steam
feed,
and the 02 stream are supplied;
the syngas producing conditions comprises the presence of an ATR catalyst in
the
reaction vessel; and
the reformed stream has at least one of the following: a temperature from 800
C to
1200 C; and an absolute pressure from 700 kPa to 5,000 kPa.
[0174] A41. The process of A40, wherein step (XV) is carried out, and in step
(XV), the BPS
stream is heated in an auxiliary furnace to obtain the SH-HPS stream.
[0175] A42. A process comprising:
(1) supplying a hydrocarbon feed and a steam feed into a syngas producing unit
comprising a reforming reactor under syngas producing conditions to produce a
reformed
stream exiting the reforming reactor, wherein the syngas producing conditions
include the
presence of a reforming catalyst, and the reformed stream comprises H2, CO,
and steam;
(2) cooling the refoinied stream by using a waste heat recovery unit ("WHRU")
to
produce a cooled reformed stream and to generate a high-pressure steam ("HPS")
stream;
(3) contacting the cooled reformed stream with a first shifting catalyst in a
first shift
reactor under a first set of shifting conditions to produce a first shifted
stream exiting the first
shift reactor, wherein the first shifted stream has a lower CO concentration
and a higher CO2
concentration than the cooled reformed stream;
(4) cooling the first shifted stream to obtain a cooled first shifted stream;
(5) contacting the cooled first shifted stream with a second shifting catalyst
in a second
shift reactor under a second set of shifting conditions to produce a second
shifted stream exiting
the second shift reactor, wherein the second shifted stream has a lower CO
concentration and
a higher CO2 concentration than the cooled first shifted stream;
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Date Regue/Date Received 2022-12-12
(6) abating steam present in the second shifted stream to produce a crude gas
mixture
stream comprising CO2 and Hz;
(7) recovering at least a portion of the CO2 present in the crude gas mixture
stream to
produce a CO2 stream and a Hz-rich stream, wherein the Hz-rich stream
comprises H2 at a
concentration of at least 80 mol%, based on the total moles of molecules in
the Hz-rich stream;
(8) combusting a portion of the Hz-rich stream in a steam cracker located in
an olefins
production plant to generate thermal energy and to produce a flue gas stream
comprising CO2
at a concentration no greater than 20 mot% based on the total moles of H2O and
CO2 in the flue
gas stream, wherein the steam cracker is operated under steam cracking
conditions to convert
a steam cracker feed into a steam cracker effluent comprising olefins;
(9) producing a CH4-rich stream from the steam cracker effluent; and
(10) providing the CH4-rich stream as at least a portion of the hydrocarbon
feed.
[0176] A43. The process of A42, wherein:
the syngas producing unit comprises a SMR;
the SMR comprises: one or more SMR burners where a SMR fuel combusts to supply
thermal energy to the SMR; a radiant section heated by the thermal energy in
which the
hydrocarbon feed and steam reacts under the syngas producing conditions; a
convection section
heated by the thermal energy in which the hydrocarbon feed and steam are
preheated before
entering the radiant section; and the process further comprises:
(11) combusting a portion of the Hz-rich stream at the plurality of SMR
burners as at
least a portion of the SMR fuel.
[0177] Various terms have been defined above. To the extent a term used in a
claim is not
defined above, it should be given the broadest definition persons in the
pertinent art have given
that twit as reflected in at least one printed publication or issued patent.
[0178] While the foregoing is directed to embodiments of the present
invention, other and
further embodiments of the invention may be devised without departing from the
basic scope
thereof, and the scope thereof is determined by the claims that follow.
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