U.S. patent application number 14/973774 was filed with the patent office on 2016-04-14 for reforming methane and higher hydrocarbons in syngas streams.
The applicant listed for this patent is DANTE P. BONAQUIST, LAWRENCE BOOL, SHRIKAR CHAKRAVARTI, RAYMOND F. DRNEVICH, STEFAN E.F. LAUX, DAVID R. THOMPSON. Invention is credited to DANTE P. BONAQUIST, LAWRENCE BOOL, SHRIKAR CHAKRAVARTI, RAYMOND F. DRNEVICH, STEFAN E.F. LAUX, DAVID R. THOMPSON.
Application Number | 20160102259 14/973774 |
Document ID | / |
Family ID | 47173850 |
Filed Date | 2016-04-14 |
United States Patent
Application |
20160102259 |
Kind Code |
A1 |
BOOL; LAWRENCE ; et
al. |
April 14, 2016 |
REFORMING METHANE AND HIGHER HYDROCARBONS IN SYNGAS STREAMS
Abstract
Oxygen is added to a raw syngas stream that contains hydrogen
and CO, one or more light hydrocarbons, and that may also contain
tars, produced by gasification of carbonaceous feed material, while
imparting heat at a rate greater than 125 BTU per pound of oxygen
added, to partially oxidize light hydrocarbons and convert tars if
present to lower molecular weight products.
Inventors: |
BOOL; LAWRENCE; (EAST
AURORA, NY) ; CHAKRAVARTI; SHRIKAR; (EAST AMHERST,
NY) ; LAUX; STEFAN E.F.; (WILLIAMSVILLE, NY) ;
DRNEVICH; RAYMOND F.; (CLARENCE CENTER, NY) ;
BONAQUIST; DANTE P.; (GRAND ISLAND, NY) ; THOMPSON;
DAVID R.; (GRAND ISLAND, NY) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
BOOL; LAWRENCE
CHAKRAVARTI; SHRIKAR
LAUX; STEFAN E.F.
DRNEVICH; RAYMOND F.
BONAQUIST; DANTE P.
THOMPSON; DAVID R. |
EAST AURORA
EAST AMHERST
WILLIAMSVILLE
CLARENCE CENTER
GRAND ISLAND
GRAND ISLAND |
NY
NY
NY
NY
NY
NY |
US
US
US
US
US
US |
|
|
Family ID: |
47173850 |
Appl. No.: |
14/973774 |
Filed: |
December 18, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
13468189 |
May 10, 2012 |
|
|
|
14973774 |
|
|
|
|
61486486 |
May 16, 2011 |
|
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Current U.S.
Class: |
518/703 ;
252/373 |
Current CPC
Class: |
Y02E 50/32 20130101;
C10J 2300/1681 20130101; C10K 1/005 20130101; C10K 1/004 20130101;
C01B 3/36 20130101; C10J 2300/1807 20130101; C01B 2203/0255
20130101; C01B 2203/062 20130101; Y02E 50/30 20130101; C10K 3/001
20130101; C10J 3/82 20130101; C10J 2300/0946 20130101; C10J 3/463
20130101; Y02P 20/145 20151101; C10K 3/005 20130101; C10J 2300/092
20130101; C10K 3/04 20130101; C10G 2/30 20130101; C10J 2300/1659
20130101; C10J 2300/0916 20130101 |
International
Class: |
C10J 3/82 20060101
C10J003/82; C10G 2/00 20060101 C10G002/00; C10K 3/00 20060101
C10K003/00 |
Claims
1. A method of syngas treatment, comprising (A) providing a raw
syngas stream obtained by gasification of carbonaceous feed
material, wherein the raw syngas stream may optionally contain
tars, and comprises hydrogen and CO as well as one or more light
hydrocarbons selected from the group consisting of methane,
hydrocarbons containing 2 or 3 carbon atoms, and mixtures thereof;
and (B) adding oxygen to the raw syngas stream while imparting heat
to the raw syngas stream at a rate greater than 125 BTU per pound
of oxygen added, and partially oxidizing one or more of said light
hydrocarbons to increase the amounts of hydrogen and CO in the
syngas while converting tars if present to lower molecular weight
products including hydrogen and CO.
2. A method according to claim 1 wherein step (B) comprises mixing
fuel and oxygen and combusting a portion of the oxygen in the
mixture with said fuel to form a hot oxidant stream that has a
temperature of at least 2000 F and that contains oxygen and
products of said combustion, and feeding said hot oxidant stream
into said raw syngas stream.
3. A method according to claim 2 wherein said fuel that is mixed
with oxygen and combusted to form said hot oxidant stream,
comprises gaseous byproducts formed in the production of product
fuels from syngas formed in step (B).
4. A method according to claim 1 wherein step (B) comprises adding
fuel and oxygen to said raw syngas and combusting said added fuel
after it is added to said raw syngas stream.
5. A method according to claim 4 wherein said fuel that is added to
said raw syngas comprises gaseous byproducts formed in the
production of product fuels from syngas formed in step (B).
6. A method according to claim 1 wherein step (B) comprises
combusting fuel and oxidant comprising at least 90 vol. % oxygen in
a burner to produce a flame that heats said raw syngas stream,
while adding oxygen to said raw syngas stream.
7. A method according to claim 6 wherein said fuel that is
combusted in said burner comprises gaseous byproducts formed in the
production of product fuels from syngas formed in step (B).
8. A method according to claim 1 wherein step (B) comprises
heating, by indirect heat transfer, oxygen that is added to said
raw syngas stream.
9. A method according to claim 1 further comprising feeding treated
syngas produced in step (B) to a reactor that produces product fuel
from said treated syngas, wherein said reactor also produces a tail
gas and liquid byproduct stream, a portion of or all of which is
added to the raw syngas and combusted to provide heat in step
(B).
10. A method according to claim 9 wherein said reactor produces one
or more products selected from the group consisting of methanol,
ethanol and F-T liquids.
11. A method according to claim 1 which further comprises
converting syngas produced by step (B) to product fuel.
12. A method of syngas treatment, comprising generating a raw
syngas stream by gasification of carbonaceous feed material,
wherein the raw syngas stream may optionally contain tars, and
comprises hydrogen and CO as well as one or more light hydrocarbons
selected from the group consisting of methane, hydrocarbons
containing 2 or 3 carbon atoms, and mixtures thereof; and treating
said raw syngas stream by the method of claim 1. (B) adding oxygen
to the raw syngas stream while imparting heat to the raw syngas
stream at a rate greater than 125 BTU per pound of oxygen added,
and partially oxidizing one or more of said light hydrocarbons to
increase the amounts of hydrogen and CO in the syngas while
converting tars to lower molecular weight products.
13. A method according to claim 12, further comprising converting
syngas produced by step (B) to product fuel.
14. A method according to claim 1 wherein said raw syngas stream
contains tars, and wherein tars in said raw syngas stream are
converted to lower molecular weight products.
Description
[0001] This application is a continuation of U.S. patent
application Ser. No. 13/468,189, filed May 10, 2012, and claims
priority from U.S. Provisional Application No. 61/486,486, filed
May 16, 2011, the entire content of which is hereby incorporated
herein by reference.
FIELD OF THE INVENTION
[0002] The present invention relates to treating syngas streams,
especially syngas streams derived from gasification of carbonaceous
feed material such as biomass.
BACKGROUND OF THE INVENTION
[0003] In the production of fuel from carbonaceous feed material
such as biomass, the carbonaceous feed material is treated to
produce a gaseous stream that contains compounds which can be
chemically converted into compounds that are useful as, for
instance, liquid transportation fuels. The present invention is
useful in the treatment of the gaseous stream (referred to herein
as "syngas"), that is formed upon gasification of carbonaceous feed
material such as biomass, to enhance the efficiency of production
of liquid transportation fuels from the syngas.
BRIEF SUMMARY OF THE INVENTION
[0004] One aspect of the invention is a method of syngas treatment,
comprising
[0005] (A) providing a raw syngas stream obtained by gasification
of carbonaceous feed material, wherein the raw syngas stream may
optionally contain tars, and comprises hydrogen and CO as well as
one or more light hydrocarbons selected from the group consisting
of methane, hydrocarbons containing 2 or 3 carbon atoms, and
mixtures thereof;
[0006] (B) adding oxygen to the raw syngas stream while imparting
heat to the raw syngas stream at a rate greater than 125 BTU per
pound of oxygen added, and partially oxidizing one or more of said
light hydrocarbons to increase the amounts of hydrogen and CO in
the syngas while converting tars if present to lower molecular
weight products, including H2 and CO.
[0007] As used herein, "biomass" means algae or material containing
any of cellulose or hemicellulose or lignin, including but not
limited to Municipal Solid Waste (MSW), wood (including wood chips,
cut timber; boards, other lumber products, and finished wooden
articles, and wood waste including sawdust, and pulpwood from a
variety of trees including birch, maple, fir, pine, spruce), and
vegetable matter such as grasses and other crops, as well as
products derived from vegetable matter such as rice hulls, rice
straw, soybean residue, corn stover, and sugarcane bagasse.
[0008] As used herein, "carbonaceous feed material" means biomass,
coal of any rank (including anthracite, bituminous, and lignite),
coke produced from coal of any rank, petroleum coke, or
bitumen.
[0009] As used herein, "fossil fuel" means product useful as fuel
that is either found in deposits in the earth and used in the form
as found, or produced by separatory and/or chemical processing of
product that is found in deposits in the earth.
[0010] As used herein, "product fuel" means hydrocarbon material
(which includes oxygenated hydrocarbon material) useful as fuel and
containing product selected from the group consisting of alkanes
liquid at 25 C and atmospheric pressure, alkenes liquid at 25 C and
atmospheric pressure, alkanols liquid at 25 C and atmospheric
pressure, and mixtures thereof. As used herein, "tars" means any
hydrocarbon with a boiling temperature at ambient conditions
greater than or equal to that of benzene, and includes mixtures of
two or more such hydrocarbons.
BRIEF DESCRIPTION OF THE DRAWINGS
[0011] FIG. 1 is a flowsheet of a process for converting biomass to
fuel, with which the present invention can be practiced.
[0012] FIG. 2 is a cross-sectional view of a hot oxygen generator
useful in the practice of the present invention.
[0013] FIG. 3 is a partial cross-sectional view of a reformer unit
useful in the practice of the present invention.
[0014] FIG. 4 is a graph of incremental combined yield of hydrogen
plus carbon monoxide against stoichiometric ratio.
[0015] FIG. 5 is a graph of incremental combined yield of hydrogen
plus carbon monoxide against residence time in a reformer unit.
DETAILED DESCRIPTION OF THE INVENTION
[0016] The present invention is particularly useful in operations
that convert biomass to product fuel. FIG. 1 is a flowsheet that
shows the typical steps of such an operation, also including a
process step that incorporates the present invention.
[0017] The following description will refer to embodiments in which
biomass feed material is treated by gasification to produce fuels
and especially alcohols and diesel. Those skilled in the art will
recognize that this embodiment can be suitably extended to other
carbonaceous feedstocks, e.g. coal, coke, petroleum coke, as well
as to the production of gasoline and other Fischer Tropsch liquids.
Also, this invention can be adapted to treatment of syngas derived
from biomass by reaction technology other than gasification of the
biomass, such as by pyrolysis. Where the following description
refers to gasification of biomass, it should not be limited to
gasification or to biomass except where specifically indicated.
[0018] Referring to FIG. 1, stream 1 of biomass is fed to
gasification unit 2. Stream 1 may previously have been treated to
lower the moisture content of the biomass, such as by heating the
biomass.
[0019] Gasification stream 3 is also fed to gasification unit 2.
Stream 3 typically contains air, steam, or oxygen, or two or all
three of air, steam and oxygen. Unit 2 may comprise one
gasification reactor or a connected series of stages which overall
achieve the desired gasification, that is, the formation of a
gaseous stream 5 which contains (at least) hydrogen and carbon
monoxide and which typically contains other substances such as
carbon dioxide, water vapor, hydrocarbons (including methane),
volatilized tars, particulate matter, and sulfides.
[0020] Typically, unit 2 comprises a moving bed gasifier, such as
Lurgi.RTM. gasifiers or a fluidized bed gasifier. Examples of
commercially available fluidized bed gasifiers include the indirect
dual-bed gasifier developed by Silvagas (current technology
provider--Rentech) or the direct O.sub.2-blown gasifier developed
by Gas Technology Institute (current technology
providers--Synthesis Energy Systems, Andritz-Carbona). A discussion
of biomass gasifiers can be found in the open literature, e.g. A
Survey of Biomass Gasification by Reed & Gaur, 2001. These
biomass gasifiers produce synthesis gas which includes hydrogen and
carbon monoxide at a molar ratio (hydrogen:carbon monoxide) of less
than 2:1. The hydrogen and the carbon monoxide are generated by
breakdown of the biomass material under conditions such that there
is not complete oxidation to water and carbon dioxide. Gasification
stream 3, which preferably contains steam and oxygen, is fed into
the bed so that it passes through the biomass and contacts the
biomass, heats the biomass, and promotes the aforementioned
breakdown of the biomass material. Gasification stream 3 is
typically fed at a temperature in the range of 100.degree. F. to
750.degree. F. and a pressure of 30 psia to 550 psia.
[0021] Within a moving bed gasifier, different reaction zones may
be present from top to bottom, namely a drying zone where moisture
is released, a devolatilization zone where pyrolysis of biomass
takes place, a gasification zone where mainly the endothermic
reactions occur, an exothermic oxidation or combustion zone, and an
ash bed at the bottom of the gasifier. If the gasification stream
contacts the biomass in a countercurrent fashion, hot dry
devolatilized biomass reacts with the relatively cold incoming
gasification stream, and hot raw gas before exiting as stream 5
exchanges heat with relatively cold incoming biomass. The
temperature profile in each part of a gasifier varies as the
biomass moves through different zones in the gasifier. In the
gasification zone, the temperature may vary between 1400.degree. F.
and 2200.degree. F.
[0022] In fluid bed gasifiers the biomass solids are effectively
completely mixed. The temperature in all parts of the bed are
essentially the same and can range from about 1200.degree. F. and
1600.degree. F. The primary benefits of a fluidized bed gasifier
are high heat transfer rates, fuel flexibility and the ability to
process feedstock with high moisture content. A variety of
fluidized bed gasifiers have been and continue to be used/developed
for biomass gasification. Key process parameters include type of
particle, size of particle and manner of fluidization. Examples of
configurations deployed for the biomass gasification application
include the bubbling fluidized bed, where bubbles of gas pass
through the solids, to circulating fluidized bed, where the
particles are carried out with the gas, subsequently separated by a
cyclone and returned to the gasifier. Fluidized bed gasifiers may
be operated below the ash fusion temperature of the feedstock, or
may have areas of the bed that are above the ash fusion temperature
to help agglomerate ash before it leaves the gasifier. The
generated syngas will contain impurities and thus will require
conditioning similar to the moving bed gasifier described above.
Tar levels may be less but still sufficient to cause problems with
downstream heat exchangers and processing units.
[0023] Low temperature gasifiers such as fluidized bed gasifiers
are likely to be more prevalent in biomass gasification
applications. With some low temperature gasifier types, such as the
bubbling fluidized bed (BFB) or circulating fluid bed (CFB) types,
the syngas can contain 5-15 vol. % CH.sub.4, 1-5 vol. % C.sub.2s
(that is, hydrocarbons containing 2 carbon atoms), and 1-100 g
tar/Nm.sup.3 syngas on a wet basis. The CH.sub.4 that is present
will act as an inert in the downstream process for production of
product fuels, be it catalytic, i.e., Fischer-Tropsch, or
fermentation. Thus, CH.sub.4 formation in the gasifier reduces the
overall fraction of carbon in the biomass being converted to
liquids/product fuel. Tars are produced by thermal decomposition or
partial oxidation of any organic material. Given the high boiling
points of these species they will condense from the syngas stream
as it is cooled before downstream processing, causing many
operational issues. Conventional syngas cleanup units typically
contain a tar scrubbing system which is expensive and maintenance
intensive.
[0024] The gas stream 5 that is produced in gasification unit 2
typically leaves the gasification unit 2 at a temperature of
between about 1000.degree. F. and 1600.degree. F.
[0025] Stream 5 is then treated in unit 4 in accordance with the
present invention (as more fully described herein) to reduce the
amounts of methane that are present in the stream and to produce
additional amounts of hydrogen and carbon monoxide (CO). If tars
are present in the stream, some or all of tars present can also be
converted to lower molecular weight products.
[0026] Stream 13 which is produced in unit 4 is preferably cooled
and treated to remove substances that should not be present when
the stream is fed to reactor 10 (described herein) that produces
fuel. Unit 6 represents a unit which cools stream 13, for instance
by heat exchange to feed water 25 to produce stream 29 of heated
water and/or steam. Unit 6 can also comprise a shift conversion
reactor in which carbon monoxide in stream 13 is reacted with water
vapor to produce hydrogen, thereby providing a way to adjust the
ratio of hydrogen to carbon monoxide in the stream.
[0027] The resultant cooled stream 14 is fed to unit 8. Unit 8
represents a conditioning stage to remove impurities 49 that may be
present such as particulates, acid gases including CO.sub.2,
ammonia, sulfur species, and other inorganic substances such as
alkali compounds. Impurities may be removed in one unit or in a
series of units each intended to remove different ones of these
impurities that are present or to reduce specific contaminants to
the desired low levels. Unit 8 represents the impurities removal
whether achieved by one unit or by more than one unit. Cooling and
impurities removal are preferably performed in the sequence shown,
but may be performed in the reverse sequence, or all in one unit.
Details are not shown, but should be obvious to those skilled in
the art. Unit 8 typically includes operations for final removal of
particulates, NH.sub.3, sulfur species and CO.sub.2 removal. The
CO.sub.2 removal is typically a performed by solvent-based process,
which either uses a physical solvent, e.g. methanol, or a chemical
solvent, e.g. amine. For installations without the addition of heat
and oxygen as in the present invention, when the syngas typically
contains on a wet basis >20 vol. % CO.sub.2 and possibly >30
vol. % CO.sub.2, it is essential to have a CO.sub.2 removal system.
Not having a CO.sub.2 removal system significantly increases the
diluent level in the syngas being fed to the liquid fuel conversion
unit. Besides lowering the H.sub.2 and CO conversion levels in the
reactor that produces product fuel, the additional CO.sub.2 will
necessitate larger equipment (piping and reactors). These
operations for removal of impurities can be carried out in separate
reactors, or two or more of them can be carried in the same
reactor, depending on the technology employed.
[0028] The resulting cooled, conditioned gaseous stream 15 contains
at least hydrogen and carbon monoxide. The exact composition can
vary widely depending on the biomass feedstock, gasifier type,
intermediate processing steps, and operating conditions. Stream 15
typically contains (on a dry basis) 20 to 50 vol. % of hydrogen,
and 10 to 45 vol. % of carbon monoxide. Stream 15 typically also
contains carbon dioxide in amounts from <1 to 35 vol. %.
[0029] Stream 15 is then fed to reactor 10 wherein product fuel is
produced. Preferably, product fuel is produced by a catalytic
conversion process, e.g. Fischer-Tropsch process. However, the
present invention is advantageous also when the product fuel is
produced by fermentation or other conversion mechanisms. If a
catalytic conversion process is used then stream 15 may require
some compression before being fed to reactor 10 depending on the
pressure of stream 15. If the end-product is a diesel-type of fuel,
a single stage of compression may suffice. For alcohols, e.g.
methanol, ethanol, 2-3 stages of compression may be required.
[0030] Considering Fischer-Tropsch conversion in general, the
Fischer-Tropsch reaction may be carried out in any reactor that can
tolerate the temperatures and pressures employed. The pressure in
the reactor is typically between 300 psia and 1500 psia, while the
temperature may be between 400.degree. F. and 700.degree. F. The
reactor will thus contain a Fischer-Tropsch catalyst, which will be
in particulate form. The catalyst may contain, as its active
catalyst component, Co, Fe, Ni, Ru, Re and/or Rh. The catalyst may
be promoted with one or more promoters selected from an alkali
metal, V, Cr, Pt, Pd, La, Re, Rh, Ru, Th, Mn, Cu, Mg, K, Na, Ca,
Ba, Zn and Zr. The catalyst may be a supported catalyst, in which
case the active catalyst component, e.g. Co, is supported on a
suitable support such as alumina, titania, silica, zinc oxide, or a
combination of any of these.
[0031] In the Fischer-Tropsch conversion, the hydrogen and carbon
monoxide in stream 15 react under pressure in the presence of a
catalyst at reaction temperature in the indicated range to yield a
mixtures of alkanols, or mixtures of alkanes and alkenes, which may
contain 1 to greater than 60 carbon atoms. Water and carbon dioxide
are also produced.
[0032] As the Fischer-Tropsch reaction is exothermic,
steam-producing cooling coils are preferably present in the
Fischer-Tropsch reactors to remove the heat of reaction. In some
types of reactors, fresh catalyst is preferably added to reactor 10
when required without disrupting the process to keep the conversion
of the reactants high and to ensure that the particle size
distribution of the catalyst particles is kept substantially
constant. In other types of reactors, such as packed-bed reactors,
such fresh catalyst addition is not necessary; instead, catalyst is
removed and replaced on a periodic basis
[0033] The manner of carrying out a variation of the
Fischer-Tropsch reaction for producing alcohols from syngas is well
known and has been practiced for several years. Useful disclosure
is found in "Synthesis of Alcohols by Hydrogenation of Carbon
Monoxide". R. B. Anderson, J. Feldman and H. H. Storch, Industrial
& Engineering Chemistry, Vol. 44, No. 10, pp 2418-2424 (1952).
Several patents also describe different aspects of the
Fischer-Tropsch conversion process that can be practiced to produce
alkanols including ethanol. For example, U.S. Pat. No. 4,675,344
provides details on process conditions, e.g. temperature, pressure,
space velocity, as well as catalyst composition to optimize the
Fischer-Tropsch process for increased production of C2 to C5
alcohols versus methanol. This patent also indicates that a
desirable hydrogen:carbon monoxide ratio in the gas feed stream is
in the range of 0.7:1 to 3:1. U.S. Pat. No. 4,775,696 discloses a
novel catalyst composition and a procedure for synthesis of
alcohols via the Fischer-Tropsch conversion. U.S. Pat. No.
4,831,060 and U.S. Pat. No. 4,882,360 provide a comprehensive
discussion on the preferred catalyst composition and synthesis
procedures for a producing a product mix with a higher ratio of
C2-5 alcohols versus methanol. The catalyst is typically comprised
of: [0034] (1) A catalytically active metal of molybdenum, tungsten
or rhenium, in free or combined form; [0035] (2) A co-catalytic
metal of cobalt, nickel or iron, in free or combined form; [0036]
(3) A Fischer-Tropsch promoter, e.g. alkali or alkaline earth
metals such as potassium; [0037] (4) An optional support, e.g.
alumina, silica gel, diatomaceous earth. Use of the above catalyst
composition provides both high production rates and high
selectivities.
[0038] When the desired product fuel is methanol, the catalytic
conversion is operated in any manner known to favor the formation
of methanol, such as carrying out the reaction with a copper-zinc
catalyst.
[0039] The overall stoichiometry for the production of alcohols
from syngas using the Fischer-Tropsch process can be summarized as
follows ("Thermochemical Ethanol via Indirect Gasification and
Mixed Alcohol Synthesis of Lignocellulosic Biomass". S. Phillips,
A. Aden, J. Jechura, D. Dayton and T. Eggeman Technical Report,
NREL/TP-510-41168, April 2007):
nCO+2nH.sub.2.fwdarw.C.sub.nH.sub.2n+1OH+(n-1)H.sub.2O
As can be seen from this stoichiometry, the optimal molar ratio of
hydrogen to carbon monoxide in the syngas is 2:1. A slightly lower
ratio is compensated somewhat by the catalysts used in for mixed
alcohol production (e.g. molybdenum sulfide), which are known to
provide some water-gas shift activity. Occurrence of the water-gas
shift reaction, shown here:
CO+H.sub.2O.fwdarw.CO.sub.2+H.sub.2
in the Fischer-Tropsch reactor effectively increases the
hydrogen:carbon monoxide ratio and correspondingly, increases
conversion of syngas to ethanol.
[0040] Stream 15 can if desired be fed into one or more than one
location in the reactor or reactors that form the desired fuel (not
shown).
[0041] The mixture of products formed in reactor 10 is represented
in FIG. 1 as stream 17. This stream 17 is treated in product
recovery unit 12 to recover stream 21 of the desired product fuel,
such as ethanol, as well as stream 23 of liquid and/or solid
by-products (such as longer-chain alkanes and/or alkanols, e.g.
naphtha), and stream 19 of gaseous byproducts. Stage 12 is shown
separate from reactor 10 but in practice the
Fischer-Tropsch/catalytic reaction and the ensuing separation of
products may be carried out in one overall processing unit which
includes a series of more than one operation. Recovery of the
desired product in stage 12 is carried out by distillation or other
separatory techniques which are familiar to those experienced in
this field. In stage 12, components of stream 17 may also be
subjected to treatment such as hydrocracking, hydrotreating, and
isomerization, depending on the desired end-products and their
desired relative amounts. Another configuration could involve use
of a fermentation reactor in unit 10. The final product in this
case is typically ethanol. Here, unit 12 will typically include a
gas-liquid separator, a distillation column and a molecular sieve.
The unreacted tail gas from the gas-liquid separator constitutes
stream 19, and where employed, stream 25.
[0042] Gaseous stream 19 comprises at least one of hydrogen, carbon
monoxide, water vapor, and light hydrocarbons such as methane
and/or C2-C8 hydrocarbons with 0 to 2 oxygen atoms. For each
component of stream 19, the entire amount thereof may have been
formed in reactor 10, or the entire amount may have been fed to
reactor 10 and not reacted therein, or the amount of the component
may be a combination of amounts formed and amounts fed to reactor
10 and not reacted therein.
[0043] Stream 25, which is at least a portion or possibly all of
stream 19, can be employed in unit 4, as a fuel that is combusted
or otherwise reacted to provide heat, as described herein with
respect to the present invention. Stream 25 or a portion of stream
25 can be fed as fuel 205 (see FIG. 2) that is fed to hot oxygen
generator 202 and combusted in hot oxygen generator 202 as
described herein. Stream 25, or a portion of stream 25, can be fed
into stream 5 that is then fed into unit 4. Stream 23 can be used
as a reactant in other operations, can be used as fuel in other
process steps, or flared.
[0044] Steam (stream 31) formed from water stream 30 that is used
to remove heat from reactor 10 can be optionally fed to unit 4 or
gasification unit 2.
[0045] Referring again to FIG. 1, in unit 4 (also referred to
herein as a reformer) the present invention furnishes oxygen and
supplemental heat to the syngas stream 5. Supplemental heat can be
provided in any of various ways, as described herein. The
supplemental heat can be provided by direct heat transfer of heat
of combustion of supplementary fuel and oxidant added to the syngas
(i.e., products of combustion are contained within the syngas
stream). Alternately, electrical heating (plasma) or indirect heat
transfer of heat of combustion (generated separately) can be used
to transfer heat to the syngas. An oxidant, preferably oxygen in a
stream comprising at least 90 vol. % oxygen, is also added to the
syngas for partial oxidation of methane and tars. Optionally,
secondary reactants, such as steam or hydrocarbons, could be added
to the reformer to tailor the final syngas characteristics to the
downstream processing.
[0046] In a preferred embodiment, the supplemental heat is provided
simultaneously with the oxidant for partial oxidation by the use of
a hot oxygen generator. By injecting both the heat and the oxidant
into the syngas simultaneously with the hot oxygen generator, it is
possible to enhance mixing, accelerate oxidation kinetics and
accelerate the kinetics of the reforming of methane and tars in the
syngas stream.
[0047] Referring to FIG. 2, to provide a high velocity stream 201
of hot oxygen, stream 203 of oxidant having an oxygen concentration
of at least 30 volume percent and preferably at least 85 volume
percent is provided into a hot oxygen generator 202 which is
preferably a chamber or duct having an inlet 204 for the oxidant
203 and having an outlet nozzle 206 for the stream 201 of hot
oxygen. Most preferably the oxidant 203 is technically pure oxygen
having an oxygen concentration of at least 99.5 volume percent. The
oxidant 203 fed to the hot oxygen generator 202 has an initial
velocity which is generally within the range of from 50 to 300 feet
per second (fps) and typically will be less than 200 fps.
[0048] Stream 205 of fuel is provided into the hot oxygen generator
202 through a suitable fuel conduit 207 ending with nozzle 208
which may be any suitable nozzle generally used for fuel injection.
The fuel may be any suitable combustible fluid examples of which
include natural gas, methane, propane, hydrogen and coke oven gas,
or may be a process stream such as stream 25 obtained from stream
19. Preferably the fuel is a gaseous fuel. Liquid fuels such as
number 2 fuel oil or byproduct stream 23 may also be used, although
it would be harder to maintain good mixing and reliable and safe
combustion with the oxidant with a liquid fuel than with a gaseous
fuel.
[0049] The fuel 205 provided into the hot oxygen generator 202
combusts therein with oxidant 203 to produce heat and combustion
reaction products such as carbon dioxide and water vapor.
[0050] The combustion reaction products generated in the hot oxygen
generator 202 mix with the unreacted oxygen of the oxidant 203,
thus providing heat to the remaining oxygen and raising its
temperature. Preferably, the fuel 205 is provided into the hot
oxygen generator 202 at a velocity that is suitable to sustain a
stable flame for the particular arrangement of nozzle 208 within
generator 202. The velocity of the fuel at nozzle 208 serves to
entrain oxidant into the combustion reaction thus establishing a
stable flame. The fuel velocity enables further entraining of
combustion reaction products and oxidant into the combustion
reaction, this improving the mixing of the hot combustion reaction
products with the remaining oxygen within the hot oxygen generator
202 and thus more efficiently heating the remaining oxygen.
[0051] Generally the temperature of remaining oxidant within the
hot oxygen generator 202 is raised by at least about 500.degree.
F., and preferably by at least about 1000.degree. F. The hot oxygen
stream 201 obtained in this way is passed from the hot oxygen
generator 202 into unit 4 through a suitable opening or nozzle 206
as a high velocity hot oxygen stream having a temperature of at
least 2000.degree. F. Generally the velocity of the hot oxygen
stream will be within the range of from 500 to 4500 feet per second
(fps), and will typically exceed the velocity of stream 203 by at
least 300 fps.
[0052] The composition of the hot oxygen stream depends on the
conditions under which the stream is generated, but preferably it
contains at least 50 vol. % O.sub.2. The formation of the high
velocity hot oxygen stream can be carried out in accordance with
the description in U.S. Pat. No. 5,266,024.
[0053] By using supplemental heat in combination with an oxidant
the partial oxidation reactions of the reforming can proceed while
consuming less of the CO and H.sub.2 that are in the raw syngas
which is fed to the reformer unit 4.
[0054] The supplemental heat must be higher than that provided by
simply preheating oxygen to 600.degree. F., (e.g. more than 125
Btu/lb of oxygen added). Increasing the temperature in the reformer
by use of supplementary heat enhances the reforming kinetics, and
therefore increases the effectiveness of the reformer in converting
tar and methane to syngas.
[0055] The injection rate of the supplementary oxidant is
preferably controlled to reform the methane and tars to form
species such as CO and H.sub.2 while reducing the formation of
CO.sub.2 and H.sub.2O which represents consumption of desirable
species.
[0056] This method of providing heat and oxygen has a number of
benefits. First, the hot oxidant stream acts as a heat carrier to
inject heat into the raw syngas. Second, the hot oxidant stream
contains radicals from the combustion of the fuel, which has been
shown to enhance reaction kinetics and tar reforming. The extremely
high velocity, high momentum hot oxidant jet also enhances mixing
between the oxidizer and the syngas. As appropriate the high
velocity jet can also be used to inject secondary reactants such as
steam by using the high velocity jet to mix oxidizer with the
secondary reactants as it also reacts with the syngas.
[0057] FIG. 3 depicts a preferred specially designed reformer 301
in which a stream 201 of hot oxygen (which optionally also contains
steam) can be mixed with the syngas 5 from biomass gasification.
This reformer 301 would be designed to provide long residence time
while minimizing capital cost requirements. The reformer design
should facilitate mixing of stream 201 with the raw syngas 5, as
well as reaction of the mixture of streams 201 and 5. One way to
accomplish this would be to provide a transitional turbulent mixing
zone 303 in which the hot oxygen fed as stream 201 and syngas fed
as stream 5 mix and ignite. This zone 303 could be simply a well
designed refractory lined duct or passage. The optimal design of
the transitional zone 303 may depend on the size of the reformer 4.
In some cases, particularly with smaller reformers it may be
possible to use a single jet of hot oxygen at any given location to
mix with the syngas. Larger installations may require multiple jets
of hot oxygen at any given location. In all cases this zone 303
should be designed to minimize `short circuiting` of the raw syngas
around the oxidant jet(s). Raw syngas that short circuits the
mixing zone will pass into and out of the reformer unreacted and
reduce the overall reformer effectiveness. Common design tools,
such as computational fluid dynamics (CFD) can be used to ensure
correct mixing. The transitional zone 303 should also be designed
to minimize heat loss. Finally, kinetic modeling has suggested that
overall reforming effectiveness is enhanced if the interior walls
of the transitional zone 303 section radiate heat to the location
of jet 201 to enhance the onset of the reforming reactions. These
kinetic simulations also suggest that a substantial portion of the
reforming takes place within the oxidant jet(s) 201 as syngas is
entrained into the jet(s) 201.
[0058] Once reaction between the syngas 5 and the hot oxidant 201
has consumed the oxygen of the hot oxidant, the resulting hot gas
mixture enters a reforming section 305 where reforming reactions,
such as the methane reforming and water gas shift reactions, are
allowed to take place. This reformer may or may not contain a
reforming catalyst. Additional heat or oxidant can be supplied to
the reformer to optimize the overall reforming effectiveness.
Residence time in the reformer should be as long as possible (2-3
seconds). Further, both the transitional zone 303 and reforming
section 305 should be designed such that deposition of char/ash
carried over from the gasifier is minimized unless provisions are
included to remove the ash during operation.
[0059] There are numerous alternative embodiments of the current
invention. The applicability of each alternative is dependent on
the combination of the raw syngas characteristics (temperature and
composition) and reformer design. Preferred alternatives are
discussed below.
Separate Injection of Heat and Oxidizer
[0060] One alternative is to add the supplemental heat as heat of
combustion produced by combusting fuel and oxidant having an oxygen
content of at least 90 vol. % within the reformer unit 4, using a
suitable burner (referred to as an oxy-fuel burner) while
separately feeding into the reformer unit oxygen required for the
partial oxidation/reforming reactions. The oxy-fuel burner fired
into the syngas stream is used to raise the temperature of the
syngas. Oxygen is injected separately for the partial oxidation of
the methane and/or tars. Since the radicals from oxy-fuel
combustion are injected separately from the oxygen for partial
oxidation, initiation of the partial oxidation reactions may be
delayed. This would lead to a longer residence time requirement to
achieve a given level of reforming. Separate injection of heat
(oxy-fuel burner) and oxygen could be used to avoid hot spots in
the reformer.
Addition of Supplementary Fuel and Oxygen to Syngas in Addition to
Oxidizer
[0061] Another embodiment of the current invention is to add
supplementary fuel and oxygen directly into the syngas in reformer
unit 4, without the use of a burner. At high enough temperatures
the fuel and oxygen will combust in the reformer and raise the
reformer temperature. Enough oxygen would need to be fed in order
to combust the added fuel and to partially oxidize the methane
and/or tars. Since heat release in this mode is more `diffuse` it
would require fairly long residence times to be effective.
Experimental data obtained for this embodiment suggest that for a
long residence time reformer this alternate mode can provide
incremental syngas yields comparable to the optimal embodiment (hot
oxygen injection). However, if the fuel is less reactive (such as
methane) then the supplementary oxygen may actually react with more
reactive syngas components, such as hydrogen, before it can react
with the target fuel.
[0062] Non-combustion heating of syngas with oxygen addition
Although many of the embodiments of the current invention provide
supplemental heat to the syngas by combustion of a supplementary
fuel, it is also possible to increase the temperature of the syngas
(in conjunction with oxygen injection) by non-combustion methods.
For example, electric heating elements could be used. Since these
elements would be operating in extreme environments, this option is
less attractive. Heat could also be added to the raw syngas through
the use of a plasma device, with or without simultaneous injection
of the oxidant or secondary reactants. If the addition of heat by
non combustion means is significantly separated from the oxidant
injection, unacceptable carbon (soot) formation may occur due to
cracking of the tars before reforming reactions can take place.
Indirect Heating of Syngas with Oxygen Addition
[0063] Heat can also be added to the syngas by indirect methods, by
which is meant that the heat generating device or combustion
products are not in direct contact with the syngas. Examples
include combustion of a supplemental fuel with an oxidant, which
could be air or a gaseous stream having an oxygen content higher
than that of air, in tubes placed in the syngas stream. This
process may be attractive from an operating standpoint since any
fuel could be used (including solids) and any oxidant could be used
(including air). However, from a thermodynamic standpoint this is
the least efficient method for heating the syngas as the outlet
temperature of the heater will be fairly high (even with air
preheating). The high process temperatures will also create
significant materials restrictions and may make this method
impractical.
Addition of Secondary Reagents in Combination with Supplemental
Heat and Oxygen
[0064] Secondary reagents injection can be integrated with the
current invention in order to tailor the characteristics of the
final syngas. For example, kinetic modeling suggests that injection
of steam (particularly steam that has been heated with an oxy-fuel
burner) has been shown to increase the yield of hydrogen while
significantly increasing the H2/CO ratio. Injection of
hydrocarbons, such as methane or large quantities of stream 19 tail
gas, can also increase the hydrogen yield while also increasing the
overall syngas (CO+H.sub.2) amount. The increase in syngas yield
associated with hydrocarbon addition reduces the concentration of
the CO.sub.2 in the final syngas, which reduces CO2 removal
costs.
[0065] By enhancing the reforming kinetics (through the use of
supplementary heat) the current invention enables reforming of tars
and methane in devices where cold oxidants would be less effective.
For example, the heat and oxidants can be injected into headspace
above the gasifier, or in a duct downstream from the gasifier,
where the residence time would be very short. Under these
conditions it would be possible to g a significant improvement in
reforming with the current invention compared to injection of
oxygen without heat.
[0066] The temperature and quantity of the preheated oxidant can be
optimized based on the final use of the `cleaned` syngas. One
extreme is mild reforming of tars with high condensation
temperatures to facilitate use of `dirty` syngas in combustion
systems. Since tars are more easily reformed than methane, less
oxygen will be required for reforming just tar. The other extreme
is the full conversion of methane and tars to CO+H.sub.2 for use in
downstream chemicals/fuels processing systems.
[0067] It should be noted that CO.sub.2 in the syngas is a diluent
in the conversion step. Depending on the CO.sub.2 content of the
syngas the final cleanup step could involve CO.sub.2 removal--an
expensive unit operation for small scale gasification systems. Such
a system is commercially available and typically deploys the use of
physical solvents, e.g. methanol, or chemical solvents, e.g.
amines. For some syngas streams, particularly those with high
CO.sub.2 concentrations, the current invention is expected to
significantly reduce the CO.sub.2 content in the syngas coming from
the biomass gasifier. For these syngas streams, this reduction in
CO.sub.2 flowrate will significantly reduce the energy consumption
(recycle rates and regeneration energy) from the CO.sub.2 removal
system or potentially eliminate the need for CO.sub.2 removal
altogether.
[0068] For these high CO.sub.2 syngas streams, operating with the
reformer with the hot oxygen generator as described herein, with
suitable O.sub.2 injection rates, may lower the CO.sub.2 levels
from >30 vol. % to <15 vol. %. This correspondingly reduces
the size of the CO.sub.2 removal system compared to what would be
required for the high CO.sub.2 concentration syngas. In some cases,
it may be advantageous to eliminate the CO.sub.2 removal system
altogether, as long as the fuel conversion process can accommodate
the additional diluent in the syngas stream. It is important to
note that the reduction in CO.sub.2 levels with the high (>20%)
CO.sub.2 concentration syngas streams is accompanied by a
simultaneous increase in CO levels, which will lower the effective
H.sub.2/CO ratio (possibly affecting the efficiency of the
Fischer-Tropsch or other fuel production operations). However, this
can be compensated for by adding H.sub.2 or H.sub.2-rich syngas to
the treated syngas that is fed to the fuel production reactor.
Therefore for those raw syngas streams with high CO.sub.2
concentrations it may be advantageous to use hot oxygen alone
(without superheated steam) for reforming.
[0069] The current invention has several advantages over the prior
art. First, in order to enhance the reforming of tars and methane
the reformer temperature must be higher than the syngas outlet
temperature typical of low temperature gasifiers. By injecting cold
oxidant, air or oxygen, into the syngas the prior art essentially
uses a portion of the syngas as `fuel` to preheat the remainder to
the operating temperature of the reformer. In the current invention
this consumption of syngas is avoided by providing an alternate
means of heating the syngas. In the optimal mode the heat and
oxygen are injected into the syngas simultaneously through the use
of a hot oxygen generator such as is described herein. The
resulting hot, reactive, jet of oxygen from the hot oxygen
generator can dramatically reduce the time for mixing and
accelerate the oxidation and reforming kinetics. This accelerated
oxidation and reforming with hot oxygen also allows tar and methane
reforming to occur in much shorter residence times and lower
temperatures than with cold oxygen in the prior art.
[0070] Another benefit of the current invention is related to the
increased operational flexibility of the process. By adding heat
and oxygen to the syngas independently (even if simultaneously) the
proportion of each can be varied based on the gasifier conditions.
For example, if the syngas temperature entering the reformer is
increased due to changes in gasifier operation, the amount of
supplemental heat can be reduced. The inherent flexibility of the
invention allows an operator to easily adjust parameters, such as
the total supplemental heat, amount of oxidizer, and amount of
secondary reactants in response to changes in gasifier feedstock,
raw syngas composition, or desired reformed syngas composition.
Finally, the current invention can increase the incremental
hydrogen production over the state of the art while using the same
amount of oxidant.
[0071] The proposed concept does an effective job of reforming
CH.sub.4, tar and other hydrocarbon species to H.sub.2 and CO, as
measured in terms of incremental H.sub.2 and combined CO and
H.sub.2. Also, for select syngas streams and at suitable oxygen
addition rates, there is a significant reduction in CO.sub.2 levels
in the syngas, which could ultimately translate to an increase in
the overall conversion levels of carbon in the biomass to the
desired liquid fuel. The reduction in the CO.sub.2 concentration
can also be accomplished through the use of secondary reactants
coupled with supplementary heat and oxygen. For example, a fuel
such as methane or stream 19 tail gas could be used to increase the
syngas volume, and potentially reform some of the exisiting
CO.sub.2, such that the CO.sub.2 levels in the resulting syngas are
reduced.
[0072] The current invention increases the overall process
efficiency of converting biomass to alternate fuels, such as
transportation fuels. Nominally, up to 50% of the energy in the
syngas from a biomass gasifier is contained in tars, CH.sub.4 and
other hydrocarbon species. Reforming the tar, methane, and other
hydrocarbons, increases the syngas flow-rate and allows more
product fuel to be produced for a given amount of biomass. By more
effectively utilizing the oxidant (ie, getting a higher syngas
yield per amount of oxidant) the operator can either use less
oxidant and therefore lower their costs, or use the same amount of
oxidant and get a higher specific yield. The higher specific yield
allows the operator to either reduce the biomass firing rate (if
the ethanol production portion of the process is limiting) or
produce more bio-derived transportation fuels. Both of these
strategies will increase revenue for the operator. The inherent
flexibility of the invention also allows the operator to better
optimize the system based on the feedstock being used so that only
the minimum amount of oxidant is used. Finally, by reducing the
mixing and enhancing kinetics it may be possible to reduce the size
of the secondary reformer as compared to using air or cold oxygen
alone.
[0073] It has also been determined that for some raw syngas
composition, and at suitable oxygen addition rates, there is a
significant reduction in CO.sub.2 levels in the syngas. This
reduces the size of the CO.sub.2 removal system in the final
cleanup stage for gasifiers producing these high CO.sub.2 raw
syngas streams. In some cases, it may eliminate the need for the
CO.sub.2 removal system altogether. This provides a significant
reduction in the overall capital and operating costs. Also,
shifting some of the CO.sub.2 to CO in the reformer, makes more
syngas available for conversion to a liquid fuel. This essentially
increases the biofuel yield for a given amount of biomass.
Example 1
[0074] The effectiveness of using the hot oxygen generator
described above for tar and methane reforming was evaluated using a
kinetic model. The raw syngas was assumed to leave the gasifier at
1500.degree. F. and have the composition shown in Table 1. Tar
species were modeled using C.sub.2H.sub.4 as a surrogate. The
reformer was assumed to be adiabatic and have approximately a 2.5
second residence time. FIG. 4 illustrates the effectiveness of hot
oxygen for reforming, based on the incremental CO+H.sub.2 formed.
As can be seen from the figure the addition of heat to the oxygen
increases the reforming effectiveness for a given reformer
stoichiometric ratio. This reformer stoichiometric ratio (also
referred to as "SR") is defined as the free oxygen injected into
the syngas divided by the amount of oxygen required to completely
combust the syngas. Note: the reformer SR as defined here does not
include the oxygen consumed by the supplementary fuel to generate
the heat. Although slightly more total oxygen is injected for a
given reformer SR, if oxygen consumed to generate heat is included,
the amount is small compared to the value of the added syngas.
TABLE-US-00001 TABLE 1 Raw Syngas Composition in Kinetic Studies
species vol % H.sub.2 22.0% H.sub.2O 13.0% CH.sub.4 15.0% CO 14.0%
CO.sub.2 34.0% C.sub.2H.sub.4 2.0%
[0075] In this example the supplemental heat for the reformer at
SR=0.21 can be calculated. In these calculations the oxygen
temperature was assumed to be 77.degree. F., and no secondary
reactants were used so the heat input from preheat is zero. The
fuel input was 1,780 Btu (lower heating value) per lb of total
oxygen injected. The sensible heat at 1500.degree. F. of the
reaction products from the fuel and the oxygen was 473 Btu/lb total
oxygen. Therefore in this case the supplemental heat was 1,307
Btu/lb total oxygen. If a secondary reactant, such as steam, had
been included the enthalpy of the steam at the injection
temperature would have been included as an input. The enthalpy of
the injected steam at the syngas temperature (assumed 1500.degree.
F.) would have been counted in the sensible heat portion.
Therefore, if the injected steam temperature is less than the
syngas temperature, it decreases the supplemental heat value.
TABLE-US-00002 TABLE 2 Example calculation of supplemental heat
Heat (Btu/lb O.sub.2) O.sub.2 preheat 0 Fuel 1780 Sensible heat
-473 Supplemental heat 1307
[0076] Table 3 shows the results from the kinetic model for the
optimal oxygen injection rate for this particular case. These data
illustrate that when syngas heating is combined with oxidant
injection the optimal SR (excluding the oxygen consumed to generate
heat) is actually lower than the cold oxygen case. The incremental
hydrogen and syngas (moles of H.sub.2+CO) generation are also much
higher than the cold oxygen case. Even when the analysis is
performed based on the total oxygen injection (not shown) the hot
oxygen provides higher syngas yields than cold oxygen at the same
oxygen injection rate. The H.sub.2/CO ratio of the cleaned syngas
is higher for the hot oxygen case, which can be important for
downstream processing. Further, with this particular raw syngas
composition the use of oxygen actually reduces the amount and
concentration of CO.sub.2 in the final syngas, with the hot oxygen
providing even lower CO.sub.2 concentrations than cold oxygen
alone.
TABLE-US-00003 TABLE 3 Predicted performance of hot oxygen
Reforming Raw Cold Syngas Oxygen Hot Oxygen Species (vol %) H.sub.2
22.0% 22.1% 22.6% H.sub.2O 13.0% 29.3% 28.7% CH.sub.4 15.0% 0.3%
0.4% CO 14.0% 34.1% 34.3% CO.sub.2 34.0% 15.0% 13.8% C.sub.2H.sub.4
2.0% Optimal SR* -- 0.28 0.21 H.sub.2/CO 1.57 0.62 0.66 Incremental
H.sub.2 -- 29.3% 47.2% Incremental syngas -- 357.0% 398.0%
[0077] Another aspect of the optimal embodiment is the opportunity
to minimize the size of the reformer device, or eliminate the
separate reformer completely. As illustrated in FIG. 5, when heat
is injected simultaneously with oxygen using the hot oxygen
generator as described herein, a substantial part of the reforming
(seen as incremental yield of hydrogen plus carbon monoxide versus
residence time) takes place in the first 1/2 to 1 second. For these
data hot oxygen A is defined as having a stoichiometric ratio
(total oxygen fed divided by the amount required to burn the
injected fuel) of 6. Hot oxygen B has a stoichiometric ratio of 3.
In fact, the amount of reforming with hot oxidant is much higher
than with cold oxygen at short residence times. Therefore, with hot
oxygen injection, it is possible to achieve reforming of the
biomass-derived syngas by injecting into the duct leaving the
gasifier, or by injecting the hot oxygen into the freeboard at the
top of the gasifier if it present. This would result in a
substantial reduction in capital cost and system complexity, and is
more attractive for retrofit installations.
* * * * *