Note: Descriptions are shown in the official language in which they were submitted.
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FUELS AND FUEL ADDITIVES THAT HAVE HIGH BIOGENIC CONTENT DERIVED
FROM RENEWABLE ORGANIC FEEDSTOCK
TECHNICAL FIELD
The subject matter relates generally to fuels and fuel additives that have
high biogenic content and
are derived from renewable organic feedstock.
BACKGROUND
[0001] With numerous detrimental effects of greenhouse gases having been
increasingly
documented, there is a clear need to reduce energy production from fossil
fuels, particularly from
petroleum and coal-derived fuel sources. To encourage the reduction of fossil
fuel usage,
governments are promoting the usage of fuels derived from renewable organic
sources rather than
fossil-based sources.
[0002] In the United States, the Environmental Protection Agency (EPA) has
mandated a
Renewable Fuel Standard ("RFS") under which cellulosic-based fuels generate
Cellulosic RINs
(renewable identification numbers). The RIN' s are a form of compliance
credits for Obligated
Parties (e.g., refineries). According to the RFS, the Obligated Parties are
required to blend an
increasing amount of cellulosic fuel into fossil-derived fuels.
[0003] To determine the biogenic percentage content of fuels, the EPA requires
tests that use
radiocarbon dating methods. More particularly, the current USEPA regulations,
at Section
8.1426(0(9), require parties to use Method B or Method C of ASTM D 6866 to
perform
radiocarbon dating to determine the renewable fraction of the fuel.
[0004] One known method for recovering energy from Renewable organic
material is
gasification. This involves converting at least a fraction of the renewable
organic material into a
synthesis gas ("syngas') composed mainly of carbon monoxide, carbon dioxide,
and hydrogen. In
the nineteenth century, coal and peat were often gasified into "town gas" that
provided a
flammable mix of carbon monoxide (CO), methane (CH4) and hydrogen (H2) that
was used for
cooking, heating and lighting. During World Wars I and II, biomass and coal
gasifiers were used to
produce CO and H2 to meet transportation needs. Also during the period of
World War II, it was
known that some syngas could be converted into liquid transportation fuels
using the Fisher-
Tropsch (F-T) process.
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SUMMARY OF THE INVENTION
[0005] The present disclosure, most generally, relates to fuel and fuel
additives that have high
biogenic content derived from renewable organic feedstock such as, but not
limited to MSW,
woody biomass, corn, sugarcane, grass, plants and seed oil. Generally
speaking, the feedstocks
contain relatively high concentrations of biogenic carbon (i.e., carbon
derived from plants) and
relatively low concentrations of non-biogenic carbon (i.e., carbon derived
from fossil sources).
[0006] More particularly, the present disclosure teaches that fuel and fuel
additives can be
produced by processes that provide Fischer-Tropsch liquids having high
biogenic concentration
and that provide the respective upgraded fuel products. In practice, the
relatively high
concentration of biogenic carbon is up to about 100% biogenic carbon. The
fuels and fuel additive
have essentially the same high biogenic concentration as the Fischer-Tropsch
liquids which, in
turn, contain the same concentration of biogenic carbon as the feedstock.
[0007] Various additional embodiments, including additions and modifications
to the above
embodiment, are described herein.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] The accompanying drawings illustrate one or more exemplary embodiments
and, together
with the detailed description, serve to explain the principles and exemplary
implementations of the
present inventions. One of skill in the art will understand that the drawings
are provided for
purposes of example only.
In the Drawings:
[0009] FIG. 1 shows one embodiment of an overall system for producing fuels
and fuel additives
that have high biogenic content and that are derived from Fischer-Tropsch
liquids that contains a
relatively high concentration of biogenic carbons and a relatively low
concentration of non-
biogenic carbons;
[0010] FIG. 2 shows an example of one embodiment of a gasification island;
[0011] FIG. 3 shows an example of one embodiment of a syngas conditioning
system;
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[0012] FIG. 4A shows an example of one embodiment of a CO2/H2S removal system;
[0013] FIG. 4B shows an example of another embodiment of a CO2/H2S removal
system;
[0014] FIG. 5 shows an example of one embodiment of a system for generating
Fischer-Tropsch
liquids;
[0015] FIG. 6 shows an example of one embodiment of a system for producing
refined Fischer-
Tropsch liquids from the system of FIG. 5.
DETAILED DESCRIPTION
[0016] Various exemplary embodiments of the present inventions are described
herein in the
context of converting feedstock high biogenic content into fuels and fuel
additives that have high
biogenic content.
[0017] Those of ordinary skill in the art will understand that the following
detailed description is
illustrative only and is not intended to be limiting. Other embodiments will
readily suggest
themselves to such skilled persons having the benefit of this disclosure, in
light of what is known
in the relevant arts.
[0018] In the interest of clarity, not all of the routine features of the
exemplary implementations
are shown and described. It will be appreciated that in the development of any
such actual
implementation, numerous implementation-specific decisions must be made in
order to achieve the
specific goals of the developer.
[0019] Throughout the present disclosure, relevant terms are to be understood
consistently with
their typical meanings established in the relevant art. However, without
limiting the scope of the
present disclosure, further clarifications and descriptions are provided for
relevant terms and
concepts as set forth below:
[0020] The term municipal solid waste (MSW) means, for example, the solid
waste that is
obtained from the collection of commercial and household trash. In its raw
form, MSW need not
be entirely solid, as it may contain entrained or absorbed liquids, or liquids
in containers or other
enclosed spaces. One of skill in the art will understand that MSW will have a
broad range of
compositions, and that the source of MSW need not necessarily be from a
municipality. For
purposes of this disclosure, other organic waste materials and various biomass
materials such as
vegetative matter may be equivalent to MSW.
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[0021] The term stream as used herein means any fluid or solid moving or en
route, directly or
indirectly, from one location to another. A stream is still a stream even if
it is temporarily
stationary for any length of time.
[0022] Reference to a portion of a stream or material refers to any portion of
the stream or
material, including the stream or material in its entirety. A portion of a
stream or material may be
mixed with other compositions of matter and the mixture will be considered to
comprise the
portion of the original stream or material.
[0023] The term in fluid communication with as used herein includes without
limitation both
direct and indirect fluid communication, such as, for example, through an
intermediate process
unit.
[0024] The term unit as used herein means part of a system, and may for
example comprise a
unit operation, a system or group of unit operations, a plant, and so forth.
[0025] The term syngas (synthesis gas) as used herein has the same meaning as
the term is used
by one of skill in the art. For example, syngas may comprise a combination of
carbon monoxide,
hydrogen, carbon dioxide and possibly other components such as, without
limitation, water vapor,
sulfur- or nitrogen-containing compounds, methane and other alkanes,
hydrocarbons, acid gases,
halogens and particulates.
[0026] The term separator as used herein refers to any process unit known in
the art for
performing a separation process and, depending upon context, can include
distillation columns,
membrane separation systems, ion exchange adsorption systems, thermal
adsorption, pressure
swing adsorption, molecular sieves, flash drums, absorption or adsorption
columns, wet scrubbers,
Venturi scrubbers, centrifuges, chromatographs, or crystallizers. For example,
separators may
separate vapors from liquids, liquids from liquids, vapors from liquids from
solids, fluids or solids
from solids, or fluids from solids.
[0027] The term heat exchanger as used herein includes without limitation any
heat exchanger or
heat exchange device known in the art, and more broadly, any device which
raises the enthalpy or
internal energy of a first composition of matter, decreases the enthalpy or
internal energy of a
second composition of matter, and transfers heat from the second composition
of matter to the first
composition of matter. Various heat exchange means are disclosed herein, all
of which are
encompassed within this term. The term also includes combinations or series of
multiple heat
exchange means. It includes, without limitation, shell and tube heat
exchangers, air or "fin-fan"
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coolers, refrigeration units, chillers, cooling towers, steam generators,
boilers, plate heat
exchangers, adiabatic wheel heat exchangers, plate fin heat exchangers, fluid
heat exchangers,
waste heat recovery units of any kind, or phase change heat exchangers of any
kind. They may
operate in a countercurrent, parallel, crosscurrent configuration, or any
other flow configuration,
and may involve separation of two fluids or direct contact between two fluids,
or the use of an
intermediate fluid (such as water, hot oil, molten salt, etc.) to transfer
heat from one fluid to
another.
[0028] The term compressor as used herein includes anything that is understood
as a compressor
in the normal sense of that term. In general, however, the term includes any
device that raises a
fluid from a first pressure to a second, higher pressure, either adiabatically
or non-adiabatically. It
may include any kind of compressor or pump, including without limitation,
centrifugal or axial, or
positive displacement (such as reciprocating, diaphragm, or rotary gear). The
term may also
include one or more stages of a multi-stage compressor. The term compressor
used in the singular
may also refer to multiple compressors arranged in series and/or parallel.
[0029] In Fig.1, a bio-refinery, generally designated by the numeral 17, is
fed with a stream 15
containing relatively high concentration of biogenic carbons and the
relatively low concentration
of non-biogenic carbons along with other non-carbonaceous materials. In the
preferred practice,
the relatively high concentration of biogenic carbons is up to about 80%
biogenic carbons. Among
other products, the bio-refinery produces high biogenic concentration Fischer-
Tropsch liquids
derived from the feedstock that contain a relatively high concentration of
biogenic carbons.
[0030] In the illustrated embodiment, as one example, the feedstock is
provided by a facility,
generally designated by the numeral 13 which provides a renewable organic
feedstock. The
facility 13 can be, for instance, a MSW processing facility in which non-
biogenic derived carbon
materials and non-carbonaceous materials are separated from the feed stock to
the bio-refinery.
The objective is to produce a segregated feedstock that contains a relatively
high concentration of
biogenic carbons and a relatively low concentration of non-biogenic carbons
along with other non-
carbonaceous materials found in the MSW.
[0031] As an example, the Facility 13 may process inbound MSW and separate
materials into
the following categories:
= Feedstock Material, sorted from MSW stream to be used for conversion into
fuel;
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= Recoverable Material, including but not limited to ferrous and nonferrous
metals,
cardboard, plastics, paper, and other recyclable materials that can be sorted
and shipped to
the commodities markets; and
= Residual Material, which is the remainder of the material not recycled or
used as
feedstock, which can be sent to landfill.
[0032] Some wet materials such as food waste or agricultural products which
are high in
biogenic content could be dried and added back to the feed stream along with
other materials.
Further, by recovering plastics such as High Density Polyethylene (HDPE) and
Polyethylene
Terephthalate (PET) among others, the percentage of non-biogenic carbons in
the feedstock is
reduced because the percentage of fossil-based plastics is reduced. The
biogenic percentage
content of the feedstock can significantly affect the economic value of the
cellulosic fuel additives.
[0033] It should be understood that the Facility 13 can be physically separate
facility from the
other portions of the system shown in Fig. 1. Also, it should be understood
that the Facility 13 can
be as described in co-pending United States patent application Serial No:
14/842,729.
[0034] As mentioned above, the bio-refinery 17 depicted in Fig. 1 is for
converting the stream
15 of processed feedstock into a streams 520 and 540 of Fischer-Tropsch
liquids. Particularly
noteworthy is that the high biogenic concentration Fischer-Tropsch liquids
contain the same
relatively high concentration of biogenic carbons as the input stream 15. In
other words,
percentage-wise, no non-biogenic carbons are added to the Fischer-Tropsch
liquids in the
production system and, indeed, some may be eliminated.
[0035] In the illustrated embodiment, the bio-refinery 17 includes a
gasification system,
generally designated by the numeral 21 and sometimes referred to herein as the
Gasification Island
(GI), for converting feedstock derived from renewable organic feedstock into
syngas and,
furthermore, for processing that syngas through a hydrocarbon reformer (HR),
as will described
below, to generate a high biogenic content syngas. It should be noted that the
gasification system
21 receives streams 231 and 233 that carry recycled hydrocarbon products and
intermediate
products, respectively, to the HR. Also, it should be noted that the GI 21
receives stream 27 that
carries recycled CO2 to stage 1 and stage 2 in the GI 21. As will be explained
below, the recycled
CO2 is used for moderating the water-gas-shift reaction within the steam
reformer in the GI 21 and
as a purge gas for instruments and instrument systems and the feeder systems.
[0036] Also, the GI 21 receives stream 273 of oxygen and stream 25 of F-T tail
gas.
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[0037] In the gasification island 21, generally speaking, the biogenic
carbons is converted into
biogenic syngas by a combination of steam reforming, sub-stoichiometric carbon
oxidation and
hydrocarbon reformation while producing syngas, including CO, H2 and CO2. The
syngas
product is carried by stream 29 in the illustrated embodiment.
[0038] Gasification reactions occurring in the GI 21 will be further described
below and, also,
are described in co-pending United States patent application Serial No:
14/138,635, the disclosure
of which has been incorporated herein by reference. It should be understood
that the unit
operations in the GI 21 can differ depending upon the feedstock.
[0039] The syngas stream 29 is processed in a syngas conditioning system 41,
as will be
described in more detail below, to provide a syngas feed stream 31 to an F-T
reactor system 33. It
should be noted that the syngas conditioning system 41 provides the CO2
recycle stream 27 for
recycling CO2 back to the GI 21.
[0040] The output from the F-T reactor system 33 comprises F-T fluids,
including a Heavy
Fischer Tropsch liquid (HFTL) stream 540 and a Medium Fischer Tropsch Liquid
(MFTL) stream
520, both of which are F-T hydrocarbons. Any unreacted syngas can be recycled
in the F-T
reactor 33 as will be described below. Further, the output of the F-T reactor
system 33 includes
the afore-mentioned stream 25 of F-T tail gas.
[0041] The bio-refinery includes a hydrogen recovery system to remove hydrogen
that is needed
for upgrading from the conditioned syngas. A portion of the conditioned syngas
flows through a
combination membrane/PSA unit to yield a high purity hydrogen stream for the
upgrading unit.
The recovered hydrogen (permeate) from the membrane is fed to a PSA unit and
the retentate is
combined with bypass syngas and fed forward to the FT reactor. The recovered
hydrogen is fed to
the PSA unit where a relatively pure hydrogen stream is produced (>99.5% H2)
and the PSA reject
stream is routed to the suction of the syngas compressor for recovery of the
reject syngas.
[0042] The bio-refinery 17 in Fig. 1 further includes an upgrading system 54
for receiving the F-
T fluids from the F-T system 33. That is, the Heavy Fischer Tropsch liquid
(HFTL) stream 540
and the Medium Fischer Tropsch Liquid (MFTL) stream 520 are fed to the
upgrading system 54.
The output liquid from the upgrading system 54 is carried by the stream 58 in
the illustrated
embodiment. In practice, the F-T liquids can include naphtha, diesel,
Synthetic Paraffinic
Kerosene (SPK), heavier alkanes along with iso-alkanes, oxygenates, and
olefins or combinations
of all these components.
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[0043] The gasification island system 21, as shown in detail in Fig. 2,
implements a 3-stage
gasification process. In the preferred embodiment, the 3-stage gasification
process includes:
a. Stage 1 - steam reforming;
b. Stage 2 ¨ sub-stoichiometric carbon oxidation process to gasify
unreacted carbons
from the steam reforming; and
c. Stage 3 - hydrocarbon reforming.
[0044] In the illustrated embodiment of the gasification island system 21 in
Fig. 2, stage 1
gasification is provided in the steam reformer unit, generally designated by
the numeral 251.
Unreacted carbons from the stage 1 gasification are converted into syngas in
the sub-stoichiometric
carbon oxidation unit, generally designated by the numeral 271. Al so in this
system, hydrocarbon
reforming is provided in the third stage of gasification by a hydrocarbon
reforming unit generally
designated by the numeral 215.
[0045] In the illustrated embodiment, the stage 1 gasification unit 251
selectively receives the
stream 15 of processed feedstock and produces a stream 254 of syngas.
Gasification unit 271
receives unreacted carbon from gasification unit 251 and produces a stream 277
of syngas. Syngas
steams 254 and 277 are combined to form syngas stream 219. And, the
gasification unit 211
receives the stream 27 of recycled CO2. In the gasification unit 211, the
recovered high biogenic
CO2 in stream 27 can be used to assist in fluidizing the bed materials,
moderating the water-gas-
shift reaction and purging instruments in a steam reformer, in a sub-
stoichiometric carbon
oxidation unit and in the hydrocarbon reformer. Also, the recovered high
biogenic CO2 in stream
27 can be added to stream 15 of processed feedstock.
[0046] The gasification unit 211 in the embodiment of Fig. 2 includes a steam
reformer,
generally designated by the numeral 251, and the sub-stoichiometric carbon
oxidation unit 271. It
is the steam reformer 251 that initially receives the stream 15 of processed
feedstock. Also, it is the
steam reformer 251 that initially receives the stream 273 of oxygen.
[0047] As shown, the steam reformer 251 preferably includes an indirect heat
source 253. The
output streams from the steam reformer 251 include a stream 254 of syngas and
a stream 256 of
solids. The syngas stream 254 is carried to the hydrocarbon reforming unit
215. The solids stream
256, primarily comprised of ash and fine char, is carried to the sub-
stoichiometric carbon oxidation
unit 271.
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[0048] In the preferred embodiment, the steam reformer 211 is a fluidized bed
design, utilizing
superheated steam, CO2, and 02 as the bed-fluidizing medium. In another
embodiment only
steam and 02 are used as a bed-fluidizing medium. Preferably, externally-fired
indirect heaters
253 maintain the reformer bed temperature and provide much of the energy to
support the
endothermic reactions required in the gasification process. The process gas
stream can exit the
steam reformer 211 through a series of cyclones. Preferably, an internal
cyclone separates and
returns the majority of any entrained bed media to the reformer fluidized bed
while a second
external cyclone collects unreacted char for further conversion to syngas in
the sub-stoichiometric
carbon oxidation unit 271. In practice, flue gas from the steam reformer's
indirect heaters is used
in a fire tube boiler to generate steam for plant use.
[0049] The illustrated hydrocarbon reformer unit 215 receives the syngas
stream 219 and
produces the afore-mentioned primary stream 29 of syngas containing CO, H2 and
CO2 along with
other trace constituents. Further, the hydrocarbon reformer unit 215 receives
stream 273 of
oxygen and stream 25 of F-T tail gas. Finally, the hydrocarbon reformer unit
215 receives stream
231 of naphtha and stream 233 of off gas.
[0050] The hydrocarbon reformer unit 215 operates to recover the biogenic
carbons by
thermally dissociating hydrocarbons at temperatures greater than 2200 degrees
F. Heat for the
hydrocarbon reformer is provided by sub-stoichiometric oxidation of carbon
monoxide and,
hydrogen and hydrocarbons which are all exothermic reactions.
[0051] The hydrocarbon reformer unit 215, in the embodiment of Fig. 2,
includes a syngas
cooling section 225. The syngas cooling section can comprise either a radiant
slagging cooler
design or a recycle syngas slagging quench design.
[0052] In preferred practice, the hydrocarbon reforming unit 215 is a
refractory-lined vessel with
oxygen gas burner/mixer which operates in the range of 1800 F to 3000 F to
assure all
hydrocarbon compounds in the gas stream, including tars are converted to
syngas, sulfur
compounds are converted to H2S, and the water gas shift reactions approach
equilibrium. The FT
Tail Gas purged from the FT reaction loop, the purification system off gas,
and stream 231 of
vaporized naphtha are converted back to CO and H2 .in the hydrocarbon
reforming unit 215.
[0053] The sub-stoichiometric carbon oxidation unit 271, in addition to
receiving the solids
stream 256, receives the stream 27 of recycled CO2 stream and a stream 273 of
oxygen. Heating
in the carbon sub-stoichiometric oxidation unit 271 is provided by sub-
stoichiometric oxidation of
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the unreacted carbons. A stream 275 of low pressure steam, is superheated in
the carbon sub-
stoichiometric oxidation unit and used as fluidization steam for both stage 1
and stage 2
gasification. The output of the carbon sub-stoichiometric oxidation unit 271
is syngas stream 277
which, in the illustrated embodiment, joins with the syngas stream 254 from
steam reformer 251 to
form syngas stream 219 which is fed to the hydrocarbon reformer unit 215.
[0054] In the preferred embodiment, the sub-stoichiometric carbon oxidation
unit 271 utilizes a
fluidized bed in which oxygen is added with the fluidization steam and CO2 to
further convert the
fine char to syngas. The gasses generated in and passing through the carbon
sub-stoichiometric
oxidation unit 271 pass through an external cyclone and re-enter the main
syngas stream 219
which is fed to the hydrocarbon reformer unit 215. The ash removed in the
cyclone is cooled and
transported to the collection silo for offsite disposal. Heat exchangers,
submerged in the fluid bed
of the sub-stoichiometric carbon oxidation unit 271 remove some heat by
superheating low-
pressure steam to 1100 F for use in the fluidization bed steam reformer 251
and the fluidization
bed of the sub-stoichiometric carbon oxidation unit 271.
[0055] In operation of the system of Fig. 2, within the fluidized bed of the
Steam Reformer 251,
externally fired heaters rapidly heat the circulating bed media and the
feedstock entering the
vessel. The feedstock almost immediately undergoes drying and pyrolysis
creating gaseous and
solid (char) products. The gaseous pyrolysis products undergo water-gas shift
reactions and
together with simultaneous steam reforming of the solid char material, produce
a syngas primarily
made up of H2, CO, CO2, and some hydrocarbons. Most remaining char then reacts
with
superheated steam and oxygen to produce syngas. Char that escapes the Steam
Reformer is
separated via a cyclone and dropped into the sub-stoichiometric carbon
oxidation unit for
additional gasification and conversion. The Steam Reformer and carbon sub-
stoichiometric
oxidation unit utilize internal and external cyclones to separate and retain
bed media that becomes
entrained in the process gas stream. From the Steam Reformer and carbon sub-
stoichiometric
oxidation unit the syngas flows to the hydrocarbon reformer Unit to convert
any remaining char,
hydrocarbons, and tars into syngas.
[0056] As mentioned above, the output of the hydrocarbon reformer unit 215 is
the syngas
stream 29 which is fed to the syngas conditioning system 41. The syngas
conditioning system 41
will now be described in conjunction with Fig. 3.
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[0057] As shown in FIG. 3, the exemplary syngas conditioning system, which has
been generally
designated by the numeral 41, receives the primary syngas stream 29 and
conditions that stream to
produce the gaseous feed stream 31 to F-T reactors. In the illustrated
embodiment, the syngas
conditioning system 41 includes, sequentially in fluid flow communication, a
Syngas Heat
Recovery Steam Generator (HRSG) unit 411 for waste heat recovery, a syngas
scrubber unit 421, a
syngas compressor 431, a primary guard bed 436, a water gas shift reactor 441,
ammonia removal
446, secondary guard beds 451, and a CO2/H25 removal system 461. One output of
the CO2/H25
removal system 461, in the illustrated embodiment, is a syngas feed stream
470. Another output of
the CO2/H25 removal system 461 is the stream 27 of recycled CO2.
[0058] Steam is generated from several sources inside the process. A HRSG
recovers steam
from the flue gas generated in the indirect fired heater unit 253 in the steam
reformer unit 251.
Steam is also generated in the HRSG unit 411 that recovers heat from the
syngas stream 29 leaving
the gasification island and steam is generated in the power boiler. The steam
from all three
sources are combined and superheated to provide the medium pressure steam used
as the motive
fluid in either syngas compressor (unit 431) steam turbine or a steam turbine
power generator
(figure 1). The combined medium pressure steam can have a biogenic content
equal to the
feedstock depending on the quantity of natural gas used in firing the external
heaters. In the
preferred embodiment a portion of the generated syngas is fed to a gas turbine
/ steam turbine
(combined cycle power plant) to generate a high biogenic content power that is
used to supply the
electrical demand of the plant. Another embodiment would be to use all the
syngas generated
steam to generate biogenic power and drive the syngas compressor unit 431 by
means of a steam
turbine drive.
[0059] The HRSG unit 411 functions to provide waste heat recovery. The output
of the HRSG
unit 411 is a stream 420 of the syngas and a stream of high pressure steam. In
the preferred
embodiment, a portion of the generated steam from the HSRG and other sources
is used to drive a
steam turbine that generates power which, in aggregate, is about 40% biogenic.
. In other
embodiments, the syngas generated steam would be used to generate biogenic
thermal power or to
use the generated syngas directly in a gas turbine generator to generate
biogenic power. In these
two embodiments, the biogenic content of the generated power would be the same
as the biogenic
content of the syngas and, thus, the same as the feedstock.
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[0060] The syngas scrubber unit 421 is a conventional gas scrubbing device
that receives the
syngas stream 420 and a stream 424 of caustic or other suitable alkaline
solution. The liquids
removed from the scrubber unit 421 comprise sour water stream 426 which can be
conveyed to a
wastewater treatment system. The sour water may contain undesirable
contaminants such as, for
example, ash particles, acids, mercury, and acidic compounds such as
hydrochloric acid (HC1) and
hydrogen sulfide (H2S) that are removed from the syngas. Syngas scrubbing is
further described in
co-pending United States patent application Serial No: 14/138,635, the
disclosure of which has
been incorporated herein by reference. The scrubbed syngas is conveyed in
stream 428.
[0061] The syngas scrubber unit 421 is provided to remove contaminants that
can potentially
damage downstream equipment and affect the F-T synthesis catalyst performance.
Preferably, the
syngas scrubber unit has three primary sections: a Venturi scrubber, a packed
tower section, and a
direct contact cooler section. If a syngas quench cooler is utilized then
approximately half of the
cleaned syngas leaving the syngas scrubber unit will be circulated back to the
hydrocarbon
reformer quench cooler via the quench blowers while the remaining half will be
compressed in the
syngas compressor 431 to meet the requirements of the F-T synthesis process.
If a radiant slagging
cooler is employed the recycle gas blower will not be required and the flow
from into the scrubber
will equal the flow leaving the gasification island 21.
[0062] In the illustrated embodiment, a syngas compressor stage 431 comprising
one or more
conventional compressor stages 433 arranged in series to raise the pressure of
a compressor inlet
stream comprising at least a portion of the syngas stream to a predefined
level, thereby outputting a
compressed syngas stream 434. In practice, the final pressure of the syngas
stream may range
between about 400 psig to about 600 psig to meet the process requirements of
the F-T synthesis
process. Preferably, the heat of compression is removed with intercoolers
after all but the final
stage each of compression; all condensed water can be collected and sent to
the waste water
treatment plant for recovery. The outlet of the compressor is sent hot to
primary guard bed 436
where any COS and HCN is hydrolyzed to H25 and NH3 and then to the shift
reactor 441.
[0063] In one embodiment, the syngas compressor drive is an
extraction/condensing turbine that
is driven by superheated high pressure steam with a portion of the steam
extracted at low pressure
for process requirements. Also, the F-T recycle compressor can be on the
syngas compressor shaft
and driven by the syngas compressor steam turbine drive. In another embodiment
the syngas
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compressor is driven by an electric motor which is energized from the power
generated in a
combined cycle power plant using syngas as a fuel to produce high biogenic
power.
[0064] The water gas shift reactor 441 receives a portion of the pressurized
primary syngas
stream 440. The water gas shift reactor 441 operates to shift some of the
steam and CO into H2
and CO2, via the water gas shift reaction, until the required H2/C0 ratio in
the outlet stream 450 is
met. Subsequently, a side stream 442 of the pressurized primary syngas may
bypass the water gas
shift reactor 441 and may be recombined with an outlet stream 450 from the
water gas shift reactor
441. High pressure steam is generated in the water gas shift unit to remove
the heat of the shift
reaction. The generated steam is fed back into the syngas stream 440 feeding
the reactor to
provide the hydrogen source for the shift reaction. Any additional steam
requirements come from
the plant steam system.
[0065] In the embodiment of Fig. 3, the outlet stream 450 of syngas from the
water gas shift
reactor 441 is conveyed to a conventional ammonia removal unit 446. In the
ammonia removal
unit 446, the syngas is cooled until the excess water condenses out with
scrubbed absorbed
ammonia. Then, the syngas leaves the condenser 446 as stream 448. The sour
water from the
condenser 446 can be conveyed to a wastewater treatment system. The stream 448
is conveyed to
the inlet of the second guard bed 451 where any volatilized Hg is removed.
[0066] The pressurized primary syngas from the second guard beds 451 is
conveyed as a stream
460 to the CO2/H25 removal system 461. The CO2/H2S removal system 461 will be
further
described in conjunction with Figs. 4A and 4B. One output of the CO2/H25
removal system 461is
a stream 464 of sulfur. Another output is a stream 470 of syngas from which
sulfur has been
removed. The third output is the CO2 recycle stream 27.
[0067] In the illustrated embodiment, the syngas feed stream 470 is conveyed
to H25 and Arsine
guard beds 471 and, then, to an H2 recovery unit 481.
[0068] Syngas from the H25/Arsine guard beds flows into the hydrogen recovery
unit 481. The
hydrogen recovery unit 481 extracts a steam 482 of high purity H2 which is
required for the
Hydrocracking Upgrading process, as described below. The output of the H2
recovery unit 481 is
the syngas feed stream 31 to the F-T reactor 33. A third output from the
hydrogen recovery unit
481 is a stream 483 of rejected syngas. The stream 483 can be recycled to join
the stream 428.
[0069] In the preferred embodiment, the hydrogen recovery unit (HRU) 481
extracts H2 using a
combination membrane and pressure swing adsorption ("PSA") system. The HRU
membrane
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retentate gas is re-mixed with the bulk syngas stream and sent to the F-T
Reactors. The HRU PSA
purge gas is routed to the suction of the Syngas Compressor 431 and the
purified H2 stream is sent
to upgrading.
[0070] As illustrated in FIG. 5, a system for generating F-T liquids receives
the syngas feed
stream 31. The system includes one or more F-T reactors 533 and provides, as
mentioned above,
the fluids output stream 535 that comprises F-T liquids and F-T tail gas. The
FT reactor output
stream 535 is fed into a thermal separation system generally designated by the
numeral 500 to
separate the F-T liquid into its heavy F-T liquid (HFTL), medium FT liquid
(MFTL), water and the
F-T tailgas.
[0071] In the preferred embodiment as illustrated in FIG. 5, the thermal
separation system 500
includes two condensers 501 and 531 and two separators 503 and 504. The HFTL
separator 503
has outlets 518 and 520, respectively. In practice, the condenser 501 operates
using a tempered hot
water loop as cooling medium to condense and separate the HFTL liquid fraction
from the F-T
water and MFTL liquid fraction. Both the MFTL, Water and the FT Tailgas remain
in a vapor
phase. The HFTL stream is carried by the outlet 520 for storage in tank(s) 521
for further
processing. In practice, the HFTL stream 520 is composed primarily of heavy
hydrocarbon waxes
which are solid at room temperature. These waxes are kept warm above 230 F to
prevent
solidification.
[0072] Also as illustrated in FIG. 5, the thermal separation system 500
includes a second
condenser 531 that receives, via the stream 518 from the HFTL separator 503,
the F-T water and
MFTL. In practice, the second condenser 531 operates, using cooling water to
condense and
separate the F-T water and MFTL from unreacted syngas and non-condensable
hydrocarbons
(methane, etc.). The condensed F-T water and MFTL stream phase split in the
second separator
504, with the MFTL stream being routed to storage unit 522, as via stream 540,
and the F-T water
to waste water treatment via stream 542.
[0073] As Fig. 5 further shows, the F-T tail gas can be recycled to the F-T
reactors 533 via a
stream 537. In the illustrated embodiment, the F-T tail gas is separated at
the MFTL separator 504
and carried by stream 550 to a compressor 511 whose output is conveyed in the
syngas recycle line
537. Prior to the recycle compressor 511 a purge stream 552 branches off of
stream 550. The
purge stream 552 is directed to both the hydrocarbon reformer 215 via stream
25 to control
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hydrocarbon content in the recycle syngas and to the power boiler to purge
inerts from the recycle
syngas.
[0074] FIG. 6 shows an example of one embodiment of the upgrading system 54 of
Fig. 1. More
particularly, Fig. 6 illustrates a system for producing refined F-T liquids
from the system of FIG. 5.
The system illustrated in FIG. 6 includes a hydrocracker reactor unit 643
which receives liquids
from hydrocracking charge vessel 560 fed by tanks 521 and 522. In the
preferred embodiment, the
hydrocracker reactor unit 643 employs a high temperature, high pressure
catalytic process that
upgrades the HFTL and MFTL hydrocarbon streams into a transportation fuel (SPK
or Diesel).
Due to the low severity of the upgrading, the hydro-processing and
hydrocracking occur in one
reactor. The olefins and alcohols are first saturated and then the alkanes are
cracked into the SPK
range of products. The hydrocracking mechanism, which involves a protonated
cyclopropane
intermediate, forms an isomer product along with a straight chained product.
In the hydrocracker
reactor unit 643, the feed mixture passes through a series of catalyst beds
for conversion into
shorter chained hydrocarbons. However, another embodiment would pre-
fractionate the MFTL
and remove the light fraction overhead to the hydrocarbon reformer and send
the heavy fraction
along with the HFTL to the hydrocracker for upgrading. This embodiment removes
most of the
oxygenates from the stream flowing to the hydrocracker and lessens the hydro-
treating load on the
hydrocracker.
[0075] As further illustrated in FIG. 6, the hydrocracker reactor unit 643
provides the output
stream 644 which is fed to a hydrocarbon thermal separation system generally
designated by the
numeral 701 wherein the crackate is cooled, condensed, and separated into two
streams; heavy and
light crackate, using a series of heat exchangers and separator vessels.
[0076] In the illustrated embodiment of the, hydrocarbon thermal separation
system 701, the
crackate is cooled in a feed/effluent heat exchanger 702 and the heavy
crackate is separated from
the light crackate in a heavy crackate separator 703. From the heavy crackate
separator 703, the
heavy crackate and light crackate is routed to a fractionator 853, as by
streams 704 and 750. In
addition, some of the heavy crackate can be recycled to the hydrocracker 643
to keep material
flowing into the hydrocracker during startup and when the fractionation column
is malfunctioning.
[0077] In the illustrated embodiment, a light crackate separator 705 is
provided for separating
the light crackate from generated water and hydrogen. The separated light
crackate is routed to
the fractionator 853 by stream 750. The water is sent, as by line 706, to the
bio-refinery's waste
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water treatment plant for treatment. The separated hydrogen gas is routed to
recycle as by stream
708. Fresh hydrogen is introduced into the system by stream 741.
[0078] The fractionation process will now be described in greater detail. As
previously
mentioned, the fractionator 853 receives a stream 704 of heavy crackate
liquids and a stream 750
of light crackate liquids. The purpose of the fractionator 853 is to separate
the SPK or Diesel cut
from the heavy crackate fraction and the naphtha fraction. The side draw
stream 856 is fed into a
stripper column 857 to remove lights from the SPK/Diesel feed and provide
final clean up and
recovery of the SPK/Diesel products. In the fractionator 853, the incoming
heavy and light
crackate streams are combined and heated by natural gas fired heater for an
initial separation in the
fractionator column. Preferably, the fractionator 853 uses direct steam
injection to strip the low
boiling hydrocarbons from the high boiling hydrocarbons without utilizing a
high temperature
reboiler configuration.
[0079] The outputs from the fractionator 853 include overhead stream 231 that
carries recyclable
hydrocarbon products. Preferably, the overhead stream 823 which is provided
into a condenser
unit 860 where the stream is condensed and separated into three streams: main
fractionator
("MF") water stream 862, and the afore-mentioned light phase (naphtha) stream
231 and off gas
stream 233. In practice, a portion of the naphtha is refluxed back into the
fractionator 53 and a
portion is sent to a Naphtha Vaporizer for injection into the hydrocarbon
reformer. The off gas
stream 233 is recycled by the offgas Compressor to the hydrocarbon reformer
for reprocessing.
The bottoms from the fractionator column 853 are pumped to the hydrocracking
charge vessel 524,
as by stream 855, for additional hydrocracking. The water is sent to the bio-
refinery's Waste
Water Treatment plant for treatment.
[0080] Naphtha from the Fractionator OH Separator is pumped into the Naphtha
Vaporizer
where it is vaporized using low-pressure steam. The naphtha vapor then flow
into the hydrocarbon
reformer 215 of Fig. 2 for recovery. The fractionation column overhead
pressure floats on the
offgas Compressor discharge rate. The offgas Compressor provides motive force
to move the
Fractionator Overhead Separator offgas into the discharge of the Naphtha
Vaporizer. The
combined streams then flow into the hydrocarbon reformer.
[0081] The SPK product, withdrawn by the steam 856 from the upper part of the
fractionator
853, is sent to the Product Stripper column 857 for final product separation.
The heat to the
product Stripper column 857 is provided, for example, by a natural gas fired
Product Stripper
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Reboiler. The Product Stripper overhead stream recycles back to the
Fractionator 853. The
bottoms stream 800 is cooled and sent, via the stream 58, to storage unit 803
as the SPK product.
[0082] As shown in FIG. 4A, one embodiment of an exemplary CO2/H25 removal
system 461
includes a sulfur removal unit 463 that receives the stream 460. One output of
the sulfur removal
unit 463 is a stream 464 of sulfur. Another output of the removal unit 463 is
a stream 466 of
syngas from which sulfur has been removed.
[0083] The syngas stream 466 is fed to an amine solvent system, generally
indicated by the
numeral 491. In the illustrated embodiment, the amine solvent system 491A
comprises an absorber
unit 493 and a regenerator unit 495 connected in counter-current relationship.
The output of the
regenerator unit 493 is the aforementioned syngas feed stream 470. The output
of the absorber unit
495 is the aforementioned stream 27 of recycled CO2.
[0084] In the preferred embodiment of Fig 4A, the absorber unit 493 is a
column where CO2 is
removed by contact with a circulating amine/water solution. In this embodiment
the amine
absorber can remove H25 from stream 466 in the event the sulfur removal unit
under performs.
The treated syngas is water washed to remove any entrained amine solution. In
the preferred
embodiment, the cleaned syngas leaving the solvent absorber 493 is heated
using Medium Pressure
(MP) saturated steam and routed, as stream 470, to the guard bed to removal
trace H25 and
arsenic catalyst poisons prior to introduction into the F-T synthesis process.
[0085] As shown in FIG. 4B, another exemplary CO2/H25 removal system 461
includes an
amine unit where syngas stream 460 is fed to an amine solvent system,
generally indicated by the
numeral 491B. In the illustrated embodiment, the amine solvent system 491B
comprises an
absorber unit 493 and a regenerator unit 495 connected in counter-current
relationship. The output
of the regenerator unit 495 is fed to the sulfur removal unit 463. The output
of the absorber unit
493 is the aforementioned syngas feed stream 470. In this embodiment, the
absorber unit 493 is a
column where CO2 and H25 is removed by contact with a circulating amine/water
solution. The
treated syngas is then water washed to remove any entrained amine solution and
sent, as stream
470, to the final guard beds 471.
[0086] In embodiment of Fig. 4B, the regenerator overhead output stream 466
is fed to the
sulfur removal unit 463 where the H25 is removed from the reject CO2 stream.
One output of the
sulfur removal unit 463 is the aforementioned stream 27 of recycled CO2 and a
stream 464 of
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sulfur. A portion of the overhead CO2 reject stream from the Sulfur Removal
unit is compressed
and recycled back the gasification island and the excess is vented to the
atmosphere.
[0087] In operation of CO2/H25 removal system in Figs. 4A and 4B, "rich" amine
(i.e., amine
after absorption of CO2) from the absorber column passes through a lean/rich
exchanger and then
flashes into the Rich Solvent Flash Drum. The flashed gas, rich in CO and H2,
flows to the
suction of the syngas compressor for reuse in the process. The flashed rich
liquid stream flows to
the Solvent Regenerator column. In the Solvent Regenerator, the rich solvent
is heated in a steam
reboiler, driving off the absorbed CO2/H25. The "leaned" solvent flowing out
the bottom of the
Solvent Regenerator is recirculated back via the lean/rich exchanger and the
solvent cooler to the
Absorber for reuse. A portion of the overhead CO2 reject stream from the
Solvent Regenerator is
compressed and recycled back the gasification island and the excess is vented
to the atmosphere.
Preferably, the system is designed to reduce the CO2 content in the syngas
stream to <I mol% and
the H25 content to less than 5 ppmv, while minimizing the loss of CO and H2.
[0088] In the overall operation of the above-described system, multiple
reactions take place as
the feedstock is gasified. The major reaction occurs at elevated temperatures
when char (carbons)
reacts with steam to produce syngas primarily made up of hydrogen (H2), carbon
monoxide (CO),
carbon dioxide (CO2), and some hydrocarbons:
C + H20 ¨> H2 + CO
2C + 02 ¨> 2C0
C + 02 ¨> CO2
Simultaneously, the reversible "water gas shift" reaction
CO + H204¨> CO2 + H2,
approaches equilibrium conditions with the CO/ H20 and the CO2/ H2 ratios
based on the
equilibrium constant at the gasifier operating temperature. The gasification
system may be
configured, and conditions provided, so that at least the following
gasification reaction occurs:
C + H20 ¨> H2 + CO.
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Simultaneously, conditions may preferably be provided so that the following
reversible "water
shift" reaction reaches an equilibrium state determined mainly by the
temperature of the gasifier,
the pressure preferably being near atmospheric:
CO + H20 <--> CO2 + H2.
The primary FT reaction converts syngas to higher molecular weight
hydrocarbons and water in
the presence of a catalyst:
nC0 + (2n + 1)H2 Crif12õ+2 + nH20.
[0089] Further as to the overall operation of system, it should be noted that
the syngas produced
in the gasification island 21 has an insufficient quantity of hydrogen for the
effective production
and upgrading of F-T liquids. The Sour shift reactor 441 generates additional
hydrogen to increase
the H2:C0 ratio in the syngas from about 0.8 to approximately 2Ø The water
gas shift reaction
converts a portion of the CO and H20 in the syngas to H2 and CO2. The reaction
is exothermic
and occurs over a sour shift catalyst. The reaction is a "sour shift" as H25
is still present in the
syngas stream. Utility steam and steam generated by the Shift Reactor 441 are
mixed with the
syngas to provide the water for the water-gas shift reaction and to moderate
the temperature rise in
the reactor. Hydrogen production and the syngas H2:CO ratio are controlled by
bypassing a
portion of the syngas stream around the Shift Reactor. The Shift Reactor
effluent heat is recovered
by interchanging with the reactor influent syngas, generating shift reactor
steam, and pre-heating
boiler feed water.
[0090] In the preferred embodiment, typical liquids produced by the Fischer
Tropsch system
have the following characteristics:
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Table 1: Fischer Tropsch derived liquids
Comments
FT Liquids FT Liquids
Typical Carbon
Total MFTL HFTL Distribution
C7 -
Carbon Distribution C4-C26 C102
Min Max
0.08748690 0.22723568
C4-009 4 7
0.18775350 0.36320007
C10-C19 6 3 0
0.17334613 0.21692890
C20-C29 3 6
0.09127170 0.11383853
C30-C39 1 5
0.07431454 0.18320366
C40+ 4 8
0.70213245 0.70172461
+C10 > 2 6
Acidity, Total mg KOH/g 0.95
Freezing Point F 163
96.4-
Boiling Point Range F 797 311-1400
Non-hydrogen
Composition
mg/k
Water g <750
mg/k
Nitrogen g <2
mg/k
Sulfur g <2
Metals
(Al, Ca, Co, Cr, Cu, Fe, K,
Li, Mg, Mn, Mo, Na, Ni, P,
Pb, Pd, Pt, Sn, Sr, Ti, V, mg/k
Zn) g <0.1 <0.1 per metal
mg/k
Halogens g <1 <1
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[0091] The MFTL is a clear and bright liquid. The HFTL is a white wax at room
temperature,
but is normally stored and shipped in its molten state.
[0092] The creation of fuel from renewable organic feedstock by the above-
described system has
significant advantages. It provides an energy efficient system with a very low
emissions profile
and reduces, by displacement, greenhouse gases associated with the use of
petroleum and coal
derived fuel products.
[0093] The fuel additives that have high biogenic content can be used to
increase the biogenic
content of fossil-based fuels and, therefore, can substantially increases the
value of such fuels. The
additive percentage can vary widely from small fraction to substantial
fractions. For example, for
use as jet fuel, the .high biogenic content additive can be as much as 50%,
with the remainder
being fossil-based jet fuel. In the instance of diesel fuels, the fuel
additives that have high
biogenic content can be percentages that approach 100%.
[0094] Further, in the instances where the renewable organic feedstock is
derived from MSW,
the quantity of MSW entering landfills is reduced, thus dramatically reducing
harmful methane gas
emissions from landfills and mitigating the need for new or expanded
landfills.
[0095] Exemplary embodiments have been described with reference to specific
configurations.
The foregoing description of specific embodiments and examples has been
presented for the
purpose of illustration and description only, and although the invention has
been illustrated by
certain of the preceding examples, it is not to be construed as being limited
thereby.
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