U.S. patent application number 13/474494 was filed with the patent office on 2013-01-17 for sorption enhanced methanation of biomass.
The applicant listed for this patent is Matthew L. Babicki, Bowie G. Keefer, Edson Ng, Brian G. Sellars. Invention is credited to Matthew L. Babicki, Bowie G. Keefer, Edson Ng, Brian G. Sellars.
Application Number | 20130017460 13/474494 |
Document ID | / |
Family ID | 44059167 |
Filed Date | 2013-01-17 |
United States Patent
Application |
20130017460 |
Kind Code |
A1 |
Keefer; Bowie G. ; et
al. |
January 17, 2013 |
SORPTION ENHANCED METHANATION OF BIOMASS
Abstract
Disclosed embodiments provide a system and method for producing
hydrocarbons from biomass. Certain embodiments of the method are
particularly useful for producing substitute natural gas from
forestry residues. Certain disclosed embodiments of the method
convert a biomass feedstock into a product hydrocarbon by
hydropyrolysis. Catalytic conversion of the resulting pyrolysis gas
to the product hydrocarbon and carbon dioxide occurs in the
presence of hydrogen and steam over a CO.sub.2 sorbent with
simultaneous generation of the required hydrogen by reaction with
steam. A gas separator purifies product methane, while forcing
recycle of internally generated hydrogen to obtain high conversion
of the biomass feedstock to the desired hydrocarbon product. While
methane is a preferred hydrocarbon product, liquid hydrocarbon
products also can be delivered.
Inventors: |
Keefer; Bowie G.; (Galiano
Island, CA) ; Babicki; Matthew L.; (West Vancouver,
CA) ; Sellars; Brian G.; (Coquitlam, CA) ; Ng;
Edson; (North Vancouver, CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Keefer; Bowie G.
Babicki; Matthew L.
Sellars; Brian G.
Ng; Edson |
Galiano Island
West Vancouver
Coquitlam
North Vancouver |
|
CA
CA
CA
CA |
|
|
Family ID: |
44059167 |
Appl. No.: |
13/474494 |
Filed: |
May 17, 2012 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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PCT/CA2010/001859 |
Nov 18, 2010 |
|
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13474494 |
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61262485 |
Nov 18, 2009 |
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Current U.S.
Class: |
429/419 ;
422/187; 429/423; 585/242; 585/251; 585/254; 60/781 |
Current CPC
Class: |
B01D 2257/30 20130101;
Y02P 20/52 20151101; Y02P 20/152 20151101; C10J 2300/1807 20130101;
C10L 3/08 20130101; B01D 2257/108 20130101; C10J 2300/0966
20130101; B01D 2257/504 20130101; Y02E 50/10 20130101; Y02P 20/145
20151101; C10K 1/026 20130101; Y02C 10/10 20130101; B01D 53/047
20130101; C10J 2300/0976 20130101; Y02E 50/14 20130101; Y02C 10/08
20130101; B01D 2256/245 20130101; C10B 57/06 20130101; C10K 1/32
20130101; C01B 2203/0233 20130101; C10L 3/104 20130101; C10K 3/04
20130101; Y02C 20/40 20200801; C10B 53/02 20130101; C10J 2300/1662
20130101; C10B 49/22 20130101; C10J 2300/0916 20130101; B01D 53/22
20130101; C01B 2203/062 20130101; C10J 2300/0996 20130101; C01B
3/38 20130101; C10J 3/463 20130101; Y02E 20/16 20130101; Y02P
20/151 20151101 |
Class at
Publication: |
429/419 ;
585/254; 585/251; 585/242; 422/187; 429/423; 60/781 |
International
Class: |
C07C 1/22 20060101
C07C001/22; F02C 3/28 20060101 F02C003/28; H01M 8/06 20060101
H01M008/06; H01M 8/18 20060101 H01M008/18; C10G 1/08 20060101
C10G001/08; B01J 8/00 20060101 B01J008/00 |
Claims
1. A method for converting a biomass feedstock into a product
hydrocarbon, comprising: a. subjecting feedstock to fast pyrolysis
or hydropyrolysis to generate fractions of pyrolysis gas and char;
b. converting at least a portion of the pyrolysis gas in a
hydroconversion step to a product hydrocarbon and carbon dioxide
over a catalyst in the presence of hydrogen and steam, while
removing carbon dioxide by carbonation of a sorbent; c. generating
at least a portion of the hydrogen by steam reforming by reaction
between steam and a portion of the pyrolysis gas or a product
hydrocarbon; d. separating hydrogen from the hydrocarbon product,
and recycling the hydrogen so as to force hydroconversion of
biomass into the hydrocarbon product; and e. regenerating the
sorbent in a regeneration step to release the carbon dioxide.
2. The method of claim 1, in which subjecting the feedstock to fast
pyrolysis or hydropyrolysis comprises hydropyrolysis.
3. The method of claim 1, further comprising regenerating the
sorbent by heating through combustion of the char and any coke
deposited on the sorbent or catalyst.
4. The method of claim 1, further comprising regenerating the
sorbent by heating with superheated steam.
5. The method of claim 3, further comprising regenerating or
decoking the catalyst in regeneration step (e).
6. The method of claim 4, further comprising regenerating or
decoking the catalyst in regeneration step (e).
7. The method of claim 1, in which the product hydrocarbon is
methane, and where converting at least a portion of the pyrolysis
gas includes a methanation step.
8. The method of claim 1, in which the sorbent comprises CaO.
9. The method of claim 1, where converting at least a portion of
the pyrolysis gas occurs at a temperature in the range of from
about 500.degree. C. to about 650.degree. C.
10. The method of claim 1, where converting at least a portion of
the pyrolysis gas occurs at a pressure in the range of from about 1
bara to about 50 bara.
11. The method of claim 1, where regenerating the sorbent occurs at
a temperature in the range of from about 700.degree. C. to about
850.degree. C.
12. The method of claim 1, where separating hydrogen comprises
pressure swing adsorption.
13. The method of claim 1, where separating hydrogen comprises
membrane permeation.
14. The method of claim 1, further comprising providing the
catalyst in any of the following reactor configurations so that the
catalyst will cycle between distinct reaction zones for
hydroconversion and regeneration steps: a. moving bed with granular
catalyst; b. fixed bed with granular packing or monolithic
catalyst, and rotary or directional valve logic for cyclically
switching beds between reaction and regeneration steps; c. bubbling
or circulating fluidized bed.
15. The method of claim 2, further comprising providing staged
reactors for hydropyrolysis and hydroconversion steps.
16. The method of claim 7, further comprising performing
hydropyrolysis and hydroconversion steps in a single bubbling
fluidized bed reactor.
17. The method of claim 14, in which hydroconversion is performed
to produce liquid hydrocarbons, and a sorption enhanced reaction
step is performed to generate hydrogen required for the
hydroconversion step.
18. The method of claim 17, in which the liquid hydrocarbons are
produced as a first product of heavier hydrocarbons and a second
product of gasoline range hydrocarbons.
19. The method of claim 17, in which product methane is also
produced in a hydroconversion step with sorption enhanced
reaction.
20. The method of claim 1, further comprising generating electrical
power with an internal-reforming solid oxide fuel cell fuelled by
methane and hydrogen converted from the biomass feedstock.
21. The method of claim 20, in which substantially the entire anode
exhaust of the solid oxide fuel cell is provided as the source of
hydrogen and steam to hydropyrolysis step (a) or hydroconversion
step (b).
22. The method of claim 1, further comprising generating power with
a gas turbine to recover heat from regenerating the sorbent.
23. A system for producing hydrocarbons from biomass, the system
comprising: f. fast pyrolysis means operating at a process
temperature less than about 650.degree. C. for producing pyrolysis
gas and char; g. catalytic conversion means operating at a process
temperature less than about 650.degree. C. for converting the
pyrolysis gas to hydrocarbons and hydrogen by hydroconversion over
a catalyst and in presence of a CO.sub.2 sorbent; h. gas separation
means for purifying a hydrocarbon product and for recycling
hydrogen to the catalytic conversion means; and i. means for
regenerating the CO.sub.2 sorbent to release the CO.sub.2.
24. The system according to claim 23 where the fast pyrolysis means
includes a hydrogen sweep gas.
25. The system according to claim 23 in which a portion of the
hydrogen is produced in a steam reforming zone.
26. The system according to claim 23 in which hydrocarbons
converted over the catalyst are mainly methane, and the catalyst is
in a methanation zone.
27. The system according to claim 26 in which a catalyst used in
the steam reforming and methanation zones is the same catalyst.
28. The system according to claim 27 in which steam reforming and
methanation zones are combined within a hydroconversion
reactor.
29. The system according to claim 23 further comprising
regeneration means for heating and regenerating the catalyst in a
regeneration zone.
30. The system according to claim 29, further comprising means for
cyclically circulating or switching the catalyst between the
hydroconversion and regeneration zones.
31. The system according to claim 30, in which the catalyst is
supported in fixed beds with switching valves to establish the
hydroconversion and regeneration zones to which each bed is
cycled.
32. The system according to claim 31, in which the fixed beds
containing the catalyst are mounted in a rotor with rotary valve
ports sealingly engaged with fixed ports to establish the
hydroconversion and regeneration zones to which each bed is
cycled.
33. The system according to claim 28 wherein substantially all of
the hydrogen is produced in the steam reforming zone or
hydroconversion reactor.
Description
CROSS REFERENCE TO RELATED APPLICATION
[0001] This is a continuation application under 35 U.S.C. .sctn.120
of International Patent Application No. PCT/CA2010/001859, filed
Nov. 18, 2010, which claims the benefit of the earlier filing date
of U.S. Provisional Application No. 61/262,485, filed Nov. 18,
2009. Each of these prior applications is incorporated herein by
reference.
FIELD
[0002] The process of the invention applies to hydropyrolysis of
carbonaceous feedstocks, and particularly of forestry residues, to
generate higher value synthetic fuels, in particular methane and
optionally liquid hydrocarbons.
BACKGROUND
[0003] Thermochemical conversion of biomass such as sawmill wood
wastes, forestry residues and agricultural wastes into synthetic
fuels is an important emerging avenue for advancement of renewable
energy sources to supplement or replace fossils fuels. While air
blown gasification is used for generation of lower heating value
fuel gas, several variants of oxygen or steam gasification can be
used for production of syngas containing minimal nitrogen. Syngas
is a gas mixture containing mostly hydrogen and carbon monoxide,
and is a versatile feedstock for further chemical processing into a
wide range of useful fuels and chemical compounds. Syngas can be
catalytically converted into methane, Fischer-Tropsch liquid fuels,
methanol, dimethyl ether, or hydrogen. The methanation reaction of
syngas to generate methane and byproduct water vapour is typically
conducted over nickel catalysts at temperatures in the range of
about 300.degree. C. to about 400.degree. C., and preferably at
elevated pressure.
[0004] Methane is readily marketed and delivered through existing
natural gas distribution infrastructure as substitute natural gas
(SNG) for numerous end uses including space heating and electrical
power generation. Methane has considerably higher energy density
than hydrogen, and can be converted into syngas or hydrogen by
catalytic steam reforming. Modern combined cycle power plants are
conveniently fueled by natural gas. Methane is also a particularly
advantageous fuel for future high temperature fuel cell power
plants using highly endothermic internal steam reforming of natural
gas to recover high grade heat generated by the fuel cell
stack.
[0005] The reaction of steam with biomass to generate syngas is
highly endothermic, hence conducted with direct or indirect heating
by partial oxidation with air or oxygen; and is typically conducted
at much higher temperature than the subsequent exothermic
methanation reaction. The thermal mismatch between gasification and
methanation reactions is detrimental to process efficiency.
[0006] Hydrogasification has previously been investigated for
gasification of biomass. The key reaction is hydrogenation of
carbon to form methane, whose exothermicity is a great advantage
compared to other gasification approaches. As hydrogen is a premium
fuel, its consumption in large amounts has presented the appearance
of a major economic barrier.
[0007] The endothermic nature of the syngas formation reaction from
the reaction of biomass pyrolysis gas and steam requires enthalpy
heat to be added (typically by partial combustion with added
oxygen). Temperatures well in excess of 650.degree. C. are
typically required to reduce tars to reasonable levels.
[0008] The gas composition produced in biomass gasification
approaches a complex equilibrium established between CO, CO.sub.2,
H.sub.2, H.sub.2O and CH.sub.4 which is a function of temperature,
pressure and overall gas composition. Reforming reactions producing
syngas increasingly dominate the equilibrium at temperatures above
650.degree. C. at the expense of hydrocarbons, CO.sub.2 and
water.
[0009] The use of catalysts, such as the use of olivine, dolomite
or nickel coated media in fluidized beds, to enhance the rate of
syngas formation is well known. These catalysts allow a faster
reaction towards syngas equilibrium favoured under the process
conditions. Catalysts have also been used in a secondary bed in
series with the gasifier for the reduction of tars contained in the
syngas or producer gas.
[0010] An oxygen blown entrained flow gasifier may typically
operate at about 1300.degree. C. to 1500.degree. C., at which
temperatures methane and higher hydrocarbons are all nearly
entirely converted to syngas. This has the important advantage of
almost completely eliminating tar constituents, but the
disadvantage for SNG production that all of the product methane
must be generated by the exothermic methanation of syngas at much
lower temperature than the gasification temperature.
[0011] Indirect steam gasifiers (such as the US Battelle/FERCO
"Silvagas" system, the Austrian fast internally circulating
fluidized bed (FICFB) system, and the Dutch ECN "Milena" system)
operate at about 850.degree. C. These systems use twin bed
configurations, in which fluidized granular heat transfer media is
circulated between a gasification zone in which steam reacts with
the biomass to produce syngas and char, and an air-blown
regeneration zone in which the char is combusted to reheat the
media. The product syngas contains a significant admixture of
methane generated within the gasifier. While downstream processing
is required to convert or remove tar constituents, an important
advantage for SNG production is that only about 55% to 60% of the
final product methane must be generated by methanation of syngas,
since a useful fraction of the methane was already produced with
the syngas.
[0012] Some recent improvements to the twin bed gasification
approach have been based on adsorption enhanced reforming ("AER")
in which a CO.sub.2 acceptor such as lime or calcined dolomite is
included in the granular media to remove carbon dioxide by
carbonation from the gasification zone operating typically at about
600.degree. C., and to release the carbon dioxide by calcining in
the regeneration zone operating typically at about 800.degree. C.
The AER process has been disclosed by Specht et al. (European
patent publications EP 1,218,290 B1 and EP 1,637,574 A1). The
principle of the AER process is to generate hydrogen-rich syngas by
shifting the reaction equilibria of the steam reforming and water
gas shift reactions by CO.sub.2 removal. The AER process has been
tested in the FICFB twin bed system, and is being developed for SNG
production by using a molten salt methanation reactor to convert
the syngas into methane.
[0013] Twin bed indirect steam biomass gasifiers, and experimental
AER systems derived from twin bed gasifiers, have been operated at
atmospheric pressure. Air blown combustion regeneration of
pressurized fluidized beds would present challenges. ECN have
considered operation of the Milena twin bed gasification system
pressurized to about 7 bara.
[0014] There is a need to provide more efficient internally
self-sustaining generation of the hydrogen needed for
hydrogasification, which otherwise is an extremely attractive
approach for conversion of biomass and other carbonaceous
feedstocks into methane and other high value synthetic fuels.
SUMMARY
[0015] While the "sorption enhanced reforming" (SER) process [known
in Europe as "absorption enhanced reforming" or AER] concerns
generating hydrogen-rich syngas, which may be converted downstream
in a separate methanation reactor into SNG, disclosed embodiments
of the present invention concern the new principle of absorption
enhanced methanation ("SEM"). Whereas carbon is nearly entirely
removed from the feed syngas by carbonation of the sorbent in AER,
only about half of the carbon is similarly removed in SEM.
[0016] Methanation as described in this disclosure is
hydroconversion of a pyrolysis gas to produce methane, including
but not confined to the conversion of syngas to methane.
[0017] It has been found unexpectedly that maintenance of a high
hydrogen back-pressure in SEM will inhibit decomposition of methane
by steam methane reforming, while carbon oxides are preferentially
removed. Because only about half of the carbon contained in the
initial syngas is removed by carbonation in SEM, the CO.sub.2
sorbent has much lighter duty in SEM as compared with SER.
[0018] Thermodynamic modeling indicates that slightly more than
half of the carbon not rejected as char or coke deposits can be
converted to methane under conditions of hydrogen self-sufficiency.
Approximately 20% of the carbon originally in the biomass will
typically be rejected as char or coke to be combusted or gasified
in the regeneration reactor. If a supplemental source of hydrogen
is available, the conversion of feed carbon to methane can be
increased within the scope of the present invention, while even
less of the carbon will be removed by carbonation of the
sorbent.
[0019] SEM may be advantageously operated at moderately elevated
working pressures in a range of just over 1 bara to about 50 bara,
or in a preferred range of from about 5 bara to about 30 bara.
While SEM can be conducted at atmospheric pressure, the methane
concentration will be lower than at higher operating pressures,
thus making the gas separation of hydrogen and methane more
difficult. Conventional methanation requires much higher working
pressures to achieve satisfactory conversion.
[0020] A preferred CO.sub.2 sorbent for SEM is CaO, which can be
used in any suitable form, or combinations thereof, such as
calcined limestone or dolomite, or CaO on a suitable support such
as alumina. CaO is readily carbonated at working temperature around
600.degree. C. and moderate pressures from atmospheric upward. Such
temperature and pressure conditions have been found to be
favourable for the hydrogasification of biomass pyrolysis gas to
methane, and for steam reforming of methane to generate
hydrogen.
[0021] Various CO.sub.2 sorbents or "acceptors" will work in the
temperature range of from about 500.degree. C. to about 650.degree.
C. of interest for SEM. These include calcined dolomite, calcium
oxide, calcium hydroxide, lithium zirconate, lithium orthosilicate,
and other metal oxides or hydroxides that can react with carbon
dioxide to form a carbonate phase.
[0022] While hydroconversion of biomass pyrolysis gas to methane
works favourably at temperatures in the range of from about
500.degree. C. to about 650.degree. C., productive hydroconversion
of pyrolysis gas to liquid hydrocarbons requires lower temperatures
in the range of from about 300.degree. C. to about 400.degree. C.
CO and CO.sub.2 are extracted from the oxygenated pyrolysis gas by
decarbonylation and decarboxylation respectively, in parallel with
extraction of H.sub.2O by hydrodeoxygenation. As CO and H.sub.2O
can be consumed to generate H.sub.2 and CO.sub.2 by the water gas
shift reaction, it may be advantageous to remove CO.sub.2 by a
carbonation reaction in order to maximize the generation of
hydrogen by water gas shift. Suitable CO.sub.2 sorbents for the
temperature range of from about 300.degree. C. to about 400.degree.
include potassium-promoted hydrotalcites, magnesia supported on
alumina, or dolomite in combination with alkali (and particularly
potassium) promoters.
[0023] Certain disclosed embodiments provide a method for
converting a biomass feedstock into a product hydrocarbon
comprising: [0024] a. subjecting the feedstock to fast pyrolysis
with rapid pyrolytic heating in the substantial absence of oxygen,
or hydropyrolysis as fast pyrolysis in the presence of hydrogen, in
order to generate fractions of pyrolysis gas and char; [0025] b.
catalytically converting at least a portion of the pyrolysis gas to
a product hydrocarbon and carbon dioxide in the presence of
hydrogen and steam, while removing carbon dioxide by carbonation of
a sorbent; [0026] c. generating at least a portion of the hydrogen
by reaction between steam and a portion of the pyrolysis gas or a
product hydrocarbon; [0027] d. separating hydrogen from the
hydrocarbon product, and recycling the hydrogen so as to force the
conversion of biomass into the hydrocarbon product; and [0028] e.
regenerating the sorbent by heating through combustion of the char
to release the carbon dioxide.
[0029] The fast pyrolysis step may be performed with externally
heated media, e.g. circulating through a pressurized auger reactor,
and preferably as hydropyrolysis in a hydrogen atmosphere. The heat
transfer media may include circulating magnetite pellets, which are
readily separable from char according to density and magnetic
properties. Some impurities such as alkalis, other metals, sulphur,
and chloride will be partially entrained by the char. While very
fast pyrolysis will minimize char production, slower pyrolysis may
also be considered for coproduction of charcoal or biochar with
lower yield of methane and any other desirable hydrocarbon
products.
[0030] The catalytic conversion step includes catalytic
hydrogasification, such as steam hydrogasification.
Hydroconversion, hydrodeoxygenation, and hydrocracking reactions
will take place. The net reaction will be exothermic. This step may
be conducted alternatively in any suitable reactor architecture,
such as the following reactor architectures: [0031] a) bubbling or
circulating fluidized bed; [0032] b) fixed bed with granular
packing or monolithic catalyst, and rotary or directional valve
logic for cyclically switching beds between reaction and
regeneration steps; [0033] c) moving bed with granular
catalyst.
[0034] The hydrogasification process requires a source of hydrogen,
either externally supplied or internally generated. According to
certain disclosed embodiments of the present invention, steam
addition, plus moisture contained in feed biomass, provides
sufficient steam for internal, self-sustaining generation of
hydrogen required for the hydrogasification reaction to convert
biomass feedstock into methane.
[0035] Certain disclosed embodiments of the invention may be
realized by any of the following operating modes: [0036] 1.
Self-sustaining recycle of H.sub.2 generated within catalytic stage
with sufficient H.sub.2 excess to overcome incomplete recovery in
downstream gas separation of recycle H.sub.2. Methane yield is
approximately 50% of carbon after char production, balance
primarily to CO.sub.2 with preferred use of water gas shift
reaction to consume most CO. [0037] 2. Supplemental hydrogen may
provided from any combination of (a) an external source of hydrogen
rich gas, or (b) oxygen or steam gasification of char offgas, or
(c) steam methane reforming of a portion of the methane product.
[0038] 3. The process in preferred embodiments includes
methanation, regeneration and reforming steps. Higher temperature,
high steam concentration and low hydrogen concentration drive the
reforming reaction forward. Lower temperature, low steam
concentration and high hydrogen concentration drive the methanation
reaction forward. Reforming and methanation may take place in each
of the reforming and methanation steps, with the equilibrium
balance reflecting not only bed temperature but also the
steam/hydrogen ratio over the catalyst. The catalyst beds are
cooled by reforming, heated by methanation and strongly heated to
the maximum process temperature by regeneration. The reforming step
follows the regeneration step to take advantage of sensible heat in
the bed, then the methanation step follows after the catalyst bed
has been cooled by the reforming step, and then the next
regeneration step takes place to finish reheating the bed up to its
cyclic maximum temperature. Such embodiments are an inventive
extension of the known principle of cyclic reforming in which
sensible heat for repeated reforming steps is provided by
alternatingly repeated regeneration steps, with certain embodiments
of the present inventive process also including methanation steps
following reforming steps and preceding regeneration steps.
[0039] With larger steam supply, higher temperature and/or lower
operating pressure, the process may generate excess syngas or
hydrogen so that coproduction of methane and hydrogen/syngas may be
contemplated. Coproduction of methane and higher hydrocarbon fuel
commodities is also attractive.
[0040] The process also may include cleaning steps to remove
catalyst poisons (alkalis, other metals, phosphorus, sulfur,
chloride, etc.) and tars. Hot or cold clean-up process alternatives
are well known.
[0041] Hot clean-up steps include sorbents (e.g. ZnO to remove
sulphur), and catalytic tar cracking followed by cool-down in
cyclic thermal regenerator loaded with layers of fine filtration
metal matrix, porous ceramic, catalyst and adsorbent. Regeneration
can be achieved by burning off tar and coke deposits, then air
flush to cool the filtration matrix and provide hot air for front
end feed dryer.
[0042] Cold clean-up can be achieved by higher temperature oil
quench and wash, followed by lower temperature water quench and
wash.
[0043] The process may also include gas separation steps for
removing CO.sub.2, for recovering a hydrogen-enriched recycle
stream for the hydrogasification step, and/or for purifying the
product methane. Preferred gas separation alternatives include
carbonation of CaO or pressure swing adsorption (PSA) for CO.sub.2
removal, and PSA or polymeric membranes for separation of H.sub.2
from CH.sub.4.
[0044] One disclosed apparatus includes a hydropyrolysis reactor.
Alternative embodiments include a single stage reactor, or a
two-stage system including a pyrolysis or hydropyrolysis reactor as
the first stage, and a methanation or hydroconversion reactor as
the second stage. The process achieves catalytic steam
hydrogasification, with catalytic hydrocracking of tars favoured by
relatively high hydrogen partial pressure.
[0045] The process includes sequential steps for (1) the working
reaction by hydrogasification or hydroconversion combined with
sorbent carbonation, and (2) regeneration of sorbent and catalysts.
Combined regeneration of the sorbent (carbon dioxide acceptor) and
catalyst is a very attractive operating mode.
[0046] Alternative reactor configurations include fixed beds with
granular or monolithic catalyst with directional or rotary valves
for cyclic switching of beds between the process steps of working
reaction and regeneration, or fluidized beds with circulation to
achieve the process steps. Twin fluidized beds are a suitable
architecture for indirect steam gasifiers, achieving the working
reaction in one bed, and regeneration by combustion of char in the
other bed.
[0047] An important aspect of the invention is heat management.
Combined exothermicity of sorption carbonation and methanation
reactions provide abundant heat for preheating feedstock and steam
generation, with reduced need for feedstock drying. Heat for
sorbent and catalyst regeneration can be generated by combustion of
relatively low value fuels, such as byproduct char or raw biomass
feedstock.
[0048] Introduction of fibrous biomass with inconsistent properties
into pressurized pyrolysis or gasification plants is a difficult
challenge. Water slurry feed is mechanically attractive, but is
incompatible with the normal requirement that the feed biomass be
substantially dry. The present process is tolerant of relatively
wet feed, because of the strong combined exothermicity of the
methanation and sorbent carbonation reactions. Another novel
approach for slurry feed within the present invention is to provide
a pusher centrifuge dewatering system within the high pressure
containment volume of the plant.
[0049] Catalyst and sorbent regeneration can be achieved in a
regeneration reactor zone integrated with the pressurized combustor
of gas turbine, or supplied with superheated steam with optional
addition of enriched oxygen.
[0050] High methane yield can be achieved in hydrogasification,
however in absence of a supplemental source of imported hydrogen up
to half of that methane may be consumed downstream to generate
recycle hydrogen and CO.sub.2. A preferred operating mode is
defined by self-sustaining recycle of H.sub.2 generated within a
catalytic stage, with just enough H.sub.2 excess to compensate for
incomplete recovery in downstream gas separation of recycle
H.sub.2. Methane yield is approximately 50% of carbon after char
production, with the remaining carbon being converted to
CO.sub.2.
[0051] Supplemental hydrogen may provided from any combination of
(a) an external source of hydrogen-rich gas such as stranded
hydrogen offgas from a chlor-alkali or ethylene plant, or (b)
oxygen or steam gasification of char, or (c) steam methane
reforming of a portion of the methane product. The process may be
operated with any amount of hydrogen recycle, including the
limiting case of zero hydrogen recycle, in which case the methane
rich product gas will contain relatively less hydrogen but
significantly larger amounts of carbon dioxide and carbon monoxide.
In the opposite limiting case, zero methane is delivered so that
maximum hydrogen may be generated; and hydrogen-rich syngas may
then be delivered as a desired product. Coproduction of methane and
hydrogen, or hydrogen-rich syngas, is an option within the scope of
the invention.
[0052] Separation of hydrogen and methane can be achieved by
pressure swing adsorption, membrane permeation, refrigerated
hydrate formation or cryogenics. While sorption-enhanced reactors
for SMR and/or methanation have integrated bulk CO.sub.2 removal,
further purification of product streams will generally be needed to
remove slip of CO or CO.sub.2 as required.
[0053] The invention provides a wide spectrum of cogeneration
opportunities. The process can generate a range of hydrocarbon
products (methane, LPG, and liquid hydrocarbons). Syngas and
hydrogen are generated within the process, either consumed entirely
within the hydrocarbon producing hydroconversion processes, or
alternatively a portion of syngas or hydrogen may be exported as a
useful product at some penalty of reducing the conversion of
biomass carbon to hydrocarbons. Syngas is an intermediate for
synthesis of a wide range of useful fuel and chemical products.
[0054] The hydropyrolysis reaction delivers a product stream of
methane plus hydrogen, and minor amounts of CO and CO.sub.2. Syngas
may also be generated by oxygen/steam gasification of char. The
syngas generated by char gasification will typically have a low
ratio of H.sub.2 to CO, which can be upgraded by admixture with
H.sub.2 generated by the hydropyrolyser. A ratio of
H.sub.2:CO.about.2 is desirable for synthesis of methanol, dimethyl
ether, or Fischer-Tropsch hydrocarbons.
[0055] Other cogeneration opportunities provided by the invention
include the production of energy as heat or electricity. Heat
recovery within the process can readily generate steam at different
temperatures. Product or byproduct fuels can be used to power
electrical generators through gas turbines, internal combustion
engines or steam turbines. Some of the most attractive future
applications of the present invention will be obtained by
integration of high temperature fuel cells with the
hydrogasfication of biomass.
[0056] As first suggested in copending U.S. patent application Ser.
No. 11/869,555, biomass hydrogasification may be directly
integrated with SOFC power plants having enriched H.sub.2 recycle
for the anode of an internal reforming SOFC. The present invention
develops practicable implementations of that opportunity. Without
the relatively low operating pressures enabled by the inventive
sorption enhanced methanation process, it would be very difficult
to integrate the usually relatively low pressure SOFC system with
the relatively high pressure hydrogasification processes.
[0057] When the oxidant for catalyst and sorbent regeneration by
combustion of char and coke is enriched oxygen, a concentrated
product stream of CO.sub.2 can be delivered for useful applications
including enhanced oil recovery, or for disposal by underground
sequestration.
[0058] The foregoing and other objects, features, and advantages of
the invention will become more apparent from the following detailed
description, which proceeds with reference to the accompanying
figures.
BRIEF DESCRIPTION OF THE DRAWINGS
[0059] FIG. 1 is a schematic diagram of one embodiment of an
apparatus according to the present invention.
[0060] FIG. 2 shows an embodiment with integration to a gas turbine
power plant.
[0061] FIGS. 3 and 4 show an embodiment with a rotary reactor
including cyclically switched hydrogasification and regeneration
zones.
[0062] FIG. 5 shows a fluidized twin bed embodiment of the
invention.
[0063] FIG. 6 shows a two stage double twin bed fluidized
embodiment.
[0064] FIG. 7 shows a two stage embodiment, with the first stage a
fluidized bed hydropyrolysis reactor and the second stage a
methanation or hydroconversion reactor with a cyclic rotary
switching mechanism.
[0065] FIG. 8 shows an embodiment for coproduction of methane and
liquid hydrocarbons.
[0066] FIG. 9 shows an embodiment with a hydrogasification system
coupled to a solid oxide fuel cell (SOFC) for generation of
electricity.
[0067] FIG. 10 is a graph of methane conversion, methane
concentration, hydrogen concentration, and the ratio of hydrogen
output to hydrogen input from the hydrogasification reactor of the
invention, versus the ratio of carbon carbonated on the sorbent to
carbon content of the biomass feed to the process.
DETAILED DESCRIPTION
[0068] FIG. 1 shows a simplified schematic of a system or apparatus
1 according to the invention. Apparatus 1 includes a feed
preparation section 2, a feed pressurization section 3, a
hydrogasification reactor 4, a solids separation section 5, a
regeneration reactor 7, a heat recovery section 8, a tar scrubber
9, and a gas separation section 10. The gas separation section 10
separates hydrogen from methane, and may be based on selective
membranes or on pressure swing adsorption (PSA). Gas separation
section 10 delivers a substantially purified methane product stream
from conduit 11, and a hydrogen-enriched recycle stream back to
hydrogasification reactor 4 via conduit 12. It is a key feature in
some preferred embodiments of the present invention that the gas
separation system 10 can be operated so as to minimize hydrogen
concentration in the product methane stream, thus preventing most
of the hydrogen from exiting apparatus 1 until consumed in
hydrogasification to produce the desired methane product.
[0069] A membrane permeation system may be advantageously used as
gas separation system 10 for purification of product methane and
separation of hydrogen-rich gas for recycle to hydrogasification.
The polymeric membrane will selectively permeate hydrogen, carbon
monoxide, carbon dioxide and water vapour relative to methane. In
order to obtain product methane containing no more than 1%
hydrogen, three membrane stages may be used in series to
progressively concentrate methane with high recovery and purity in
the retentate stream. The feed gas is introduced to the inlet of
the first stage, from which the hydrogen-enriched recycle gas will
be delivered as low pressure permeate. The permeate of the second
stage will be recompressed to join the feed at the inlet of the
first stage, while the permeate of the third stage will be
recompressed to the inlet of the second stage.
[0070] Alternatively, pressure swing adsorption may be used as gas
separation system 10 for purification of product methane and
separation of hydrogen-rich gas for recycle to
hydrogasification.
[0071] Hydrogasification reactor 4 and regeneration reactor 7
comprise a coupled reactor pair for the working hydrogasification
reaction and regeneration steps. Each of reactors 4 and 7 comprises
at least one bed containing a CO.sub.2 sorbent, and optionally also
another solid component having catalytic and favourable heat
transfer media characteristics. It is contemplated that the beds
will cycle or be switched between the hydrogasification and
regeneration reaction zones.
[0072] Pressure and temperature conditions in the hydrogasification
reactor 4 will be selected to be favourable for combined
methanation and steam reforming reactions such that the process
achieves self-sufficiency in producing the amount of hydrogen
needed for the methanation reaction, while also favourable for the
carbonation reaction binding CO.sub.2 to the sorbent. The
regeneration reactor 7 will typically be operated at relatively
higher temperature in order to release the CO.sub.2 from the
sorbent, and may be operated at substantially the same pressure or
at lower pressure to facilitate regeneration and reduce air
compression requirements for regeneration.
[0073] A preferred CO.sub.2 sorbent is CaO, alternatively provided
by calcining of natural limestone or dolomite, or by synthesis to
achieve enhanced mesoporosity and stability for extended cycling
without rapid deactivation due to sintering and pore blockage. It
has been found in the art that composite structures comprising CaO
supported on or encapsulated in a mesoporous ceramic (e.g. alumina)
may achieve superior durability against deactivation, while also
providing a hardened external shell for superior attrition
resistance. Such mesoporous composite structures may be usefully
applied in fixed bed monoliths as well as in granular media for
fluidized bed operations. The present invention contemplates the
use of zirconia and alumina for such mesoporous composites with
CaO.
[0074] At relatively higher pressures around 30 bara and with high
steam concentrations during sorbent processing, Ca(OH).sub.2 may be
a useful intermediate between CaO and CaCO.sub.3. It is known that
the sintering longevity problems in cycling between CaO and
CaCO.sub.3 may be largely avoided by cycling between oxide,
hydroxide and carbonate compounds of the sorbent.
[0075] The regeneration gas for regeneration reactor 7 provides
heat for calcining the sorbent, and oxygen and/or steam for
decoking the catalyst, while serving as sweep gas to purge CO.sub.2
released in calcining and decoking functions. A preheater 15 is
provided to preheat air or enriched oxygen provided for oxidation
and sweep gas functions, while superheating any steam provided to
assist decoking and as sweep gas. A feed air compression unit 16 is
provided, which would usually be an air compressor. Feed air
compression unit 16 may alternatively include a feed air blower, a
pressure swing adsorption oxygen enrichment unit, and an oxygen
compressor delivering oxygen to preheater 15. Oxygen enrichment may
be desired to reduce air compression loads in higher working
pressure embodiments of the process, or to facilitate capture of
concentrated CO.sub.2 from the exhaust. A heat recovery section 18
is provided to recover heat from the CO.sub.2 and sweep gas
discharged to exhaust.
[0076] Heat recovery sections 8 and 18 are here contemplated to be
steam generators, providing steam by conduit 19 to
hydrogasification reactor 4 and optionally in some embodiments also
by conduit 20 to preheater 15 and regeneration reactor 7.
[0077] Feed preparation section 2 includes steps of sizing and
drying as necessary. Feed pressurization section 3 includes a lock
hopper system or a pressure feeder device to introduce the feed
biomass into the pyrolysis and gasification process at a working
pressure of preferably about 5 bara to about 50 bara, and more
preferably about 10 bara to about 20 bara.
[0078] Solids are removed from the effluent pyrolysis gas exiting
hydrogasification reactor 4 by a solids removal section 5 including
one or multiple cyclones, and optionally also high temperature
filters such as metallic or ceramic candle filters. A
desulfurization reactor (e.g. using zinc oxide for H.sub.2S
removal), or sorbent beds for removal of alkalis or chlorides, may
be included here for protection of any downstream catalysts.
[0079] FIG. 2 shows a simplified schematic of an alternative
apparatus 40 with the regeneration reactor 7 embedded in a gas
turbine 41 to enable the efficient use of pressurized air for
regeneration. Gas turbine 41 includes a compressor 42 coupled to a
high temperature expander 43 and a mechanical load 44 which may be
an electrical generator. The expanded exhaust from expander 43
includes vitiated air and CO.sub.2 released from the sorbent, and
is subjected to heat recovery in heat exchanger 47 before
generating steam in downstream heat recovery section 18. Heat
exchanger 47 provides heat to preheater 15 in this embodiment, and
may be directly integrated with preheater 15 in well known
recuperator or rotary regenerator embodiments well known in the gas
turbine art.
[0080] In order to protect the turbine blades of expander 43 from
erosion, corrosion or fouling damage, it is necessary to provide a
hot gas clean-up section 50 to remove solid particulate, alkalis
and any chloride or sulphur compounds that have not been retained
by the sorbent under regeneration conditions. The hot gas clean-up
section 50 will include cyclones, filters (metal fabric, ceramic
candles or precoat filters), and chemical sorbents as necessary to
capture the alkalis and any other detrimental components. Captured
solids and spent sorbents will be released from discharge conduit
51.
[0081] FIGS. 3 and 4 show an embodiment 60 with rotary fixed bed
reactors that will be particularly useful for smaller scale
applications of the invention, e.g. for local supply of methane
fuel from forestry operations in remote areas.
[0082] Reactors 4 and 7 are combined in a cyclic rotary reactor 61.
A plurality of fixed beds 62 are mounted in a rotor 63 rotating
about rotary axis 64 between a first rotary valve face 65 and a
second rotary valve face 66. First rotary valve face 65 engages
sealingly with a first valve stator face 67, and second rotary
valve face 66 engages sealingly with a second valve stator face 68.
Fluid connection ports 75, 76, 77 and 78 are provided in first
valve stator face 67, while fluid connection ports 85, 86, 87 and
88 are provided in second valve stator face 68. FIG. 4 shows the
ports for the first valve stator face, with bracketed reference
numerals for the corresponding ports of the second valve stator
face.
[0083] The biomass feed is pressurized and decomposed by pyrolysis
reactor 70 before admission to port 75. Conduits 12 and 19
respectively provide recycle hydrogen and steam to port 75. Raw
product methane gas is delivered from port 85 to heat recovery,
clean-up and purifications steps.
[0084] Preheated regeneration air is introduced to port 77, while
the CO.sub.2 containing exhaust is discharged from port 87 to heat
recovery. Cocurrent regeneration as shown in FIG. 3 may be replaced
with countercurrent regeneration by introducing the preheated
regeneration air to port 87, and discharging the exhaust from port
77.
[0085] Intermediate ports 76 and 78 in the first stator, and
intermediate ports 86 and 88 in the second stator, are provided to
enable buffer purge steps with steam or other inert gas between the
hydrogasification and regenerations steps, so as to avoid hazardous
direct contact of undiluted air with high concentration fuel gas.
The intermediate ports may also be used for pressure equalization
steps between the hydrogasification step performed at elevated
pressure and the regeneration step performed at lower pressure or
substantially atmospheric pressure.
[0086] FIG. 5 shows a circulated fluidized twin bed embodiment 100
of the invention that would be particularly applicable to larger
scale installations. Fluidized bed loop 101 includes a bubbling bed
hydrogasification reactor 4 energized by recycle hydrogen from
conduit 12 and steam from conduit 19, and a circulating fluidized
bed regenerator reactor 7 energized by feed air from compressor
42.
[0087] The fluidized bed solid media includes CaO sorbent,
preferably formed in composite mesoporous ceramic pellets. The
ceramic (preferably also impregnated with transition group metal
catalysts such as nickel, or noble metal catalysts such as rhodium
with ceria) may itself have catalytic properties for reforming of
pyrolysis gas and tars, and for methanation of syngas.
[0088] The granular media may be a mixture of sorbent, catalyst and
heat exchange particles. The media should have high heat capacity,
thermal conductivity and attrition resistance. Olivine sand is
recognized as having excellent properties as heat transfer media in
biomass gasification, including moderate catalytic properties for
reforming tar constituents. Magnetite may also be useful as heat
transfer media, with the potential advantage of downstream magnetic
separation between the heat transfer media and char.
[0089] Carbonated sorbent, char and coked catalyst are transferred
from hydrogasification reactor 4 to regenerator reactor 7 via
siphon 102. Calcined sorbent and regenerated catalyst are
transferred back from regenerator reactor 7 to hydrogasification
reactor 4 via cyclone 103 and siphon 104. Ash may be released from
the bottom of regenerator 7 by a lock hopper or an intermittently
operated valve.
[0090] FIG. 6 shows a two stage fluidized bed embodiment 150, with
the first stage 101 using relatively robust but less catalytically
active media such as olivine or nickel impregnated olivine or
glass-ceramic transition metal (e.g. Ni, Mo, W and combinations
thereof) catalysts such as developed by the Gas Technology
Institute, and the second stage 201 using more active and more
delicate catalysts and lime sorbent for improved conversion of tars
and higher yield of methane. In this embodiment, the first stage
101 is a fluidized bed reactor loop achieving hydropyrolysis and
partial conversion to methane and hydrogen, while the second stage
201 performs more complete hydroconversion.
[0091] The solids separation section 5 may here include means to
remove catalyst poisons (e.g. sulphur, chlorides, alkalis, etc.).
Second stage fluidized bed loop 201 includes the second stage
hydrogasification reactor 204, the second stage regeneration
reactor 207. Deactivated catalyst and carbonate sorbent are
transferred from hydrogasification reactor 204 to regenerator
reactor 207 via siphon 212. Calcined sorbent and regenerated
catalyst are transferred back from regenerator reactor 207 to
hydrogasification reactor 204 via siphon 214.
[0092] The hot gas effluent from regenerator reactor 207 is
delivered through cyclone 213 and hot-gas cleanup section 50 to the
inlet of gas turbine expander 43.
[0093] Fluid control means 215 is provided to control flows of
recycle hydrogen from conduit 12 and steam from conduit 19 to
energize fluidized beds in first stage reactor 101 and second stage
reactor 201. Fluid control means 215 may include control valves,
expanders or compressors as needed to control flows and regulate
pressures.
[0094] FIG. 7 shows a two stage fluidized bed embodiment 250, with
the first stage 101 a fluidized bed hydropyrolysis reactor as in
embodiments 100 or 150, and the second stage a methanation or
hydroconversion reactor 61 with a cyclic rotary switching mechanism
for rotary fixed beds 62 as shown in embodiment 60. Beds 62 are
switched cyclically between methanation or hydroconversion steps as
reactor 254, and regeneration steps as reactor 257. Hot gas cleanup
can be performed in cleanup section 250 with filtered solids and
spent sorbents removed by discharge conduit 251. Heat recovery
steam generator 258 may be provided to recover heat between first
stage hydropyrolysis reactor 4 and second stage methanation or
hydroconversion reactor 254.
[0095] FIG. 8 shows an embodiment 300 for coproduction of methane
and liquid hydrocarbons with a three stage reactor system. A
hydropyrolysis reactor 304 is provided upstream of a
hydroconversion reactor 310 for production of liquid hydrocarbons,
and itself upstream of a sorption enhanced reactor 314 for
production of hydrogen and methane. The hydrogen from reactor is
delivered to hydropyrolysis reactor 304. Reactor 304 provides rapid
heating of the biomass particles to a pyrolysis temperature in the
range from about 300.degree. C. to about 500.degree. C., in order
to decompose the biomass into pyrolysis gas (including light
hydrocarbons, some syngas, and tar vapours) and char. Heating may
be achieved by mixing the biomass particles with a granular heat
transfer media in a mechanical or fluidized bed contacting system.
Various mechanisms are well known for fast pyrolysis reactors (e.g.
auger reactors and circulating fluidized beds), and may be used in
a mechanical contacting system in reactor 304. The granular heat
transfer media should have high heat capacity, thermal conductivity
and attrition resistance. Olivine sand is recognized as having
excellent properties as heat transfer media in biomass
gasification, including moderate catalytic properties for reforming
tar constituents. Nickel-impregnated olivine has improved catalytic
properties. The glass-ceramic catalysts developed by the Gas
Technology Institute are believed to be superior for hydropyrolysis
applications. Magnetite may also be useful as heat transfer media,
with the potential advantage of downstream magnetic separation
between the heat transfer media and char.
[0096] The heat exchange media is circulated between reactor 304
and a media heater 315, with pyrolytic char being discharged from
reactor 304 with spent heat exchange media returning to the media
heater 315. Combustion of char in media heater 315 may conveniently
provide heat required for heating the feed biomass to reaction
temperature and for the endothermic pyrolysis and initial
gasification reactions. Ash is discharged from media heater
315.
[0097] A portion of the char exiting reactor 304 may be separated
from the heat exchange media by char separator 316 as the feedstock
for an auxiliary oxygen or steam gasification method to generate
syngas. After water gas shift and CO.sub.2 removal from the syngas,
supplemental hydrogen may thereby be provided for the subsequent
hydrogasification reaction. Alternatively a portion of the char
separated by char separator 316 may be diverted to other external
uses, including sale of charcoal as a solid fuel, or as a
"bio-char" soil amendment for agriculture or forestry uses with an
important purpose of carbon sequestration in the soil. Ash may also
be a useful byproduct for soil enhancement and recycle of nutrients
for overall sustainability of biomass cultivation, harvesting and
utilization.
[0098] Solids are removed from the effluent pyrolysis gas exiting
pyrolysis reactor 304 by a solids removal section 317 including one
or multiple cyclones, and optionally also high temperature filters
such as metallic or ceramic candle filters. A catalyst poison
removal section 318 (including a desulfurization reactor using zinc
oxide for H.sub.2S removal, and optionally including other sorbent
beds for removal of chlorides and/or alkalis) may be included here
for protection of downstream catalysts. The pyrolysis gas is also
cooled by a heat recovery steam generator 319, either upstream or
downstream of the catalyst poison removal sorbent beds.
[0099] The cooled pyrolysis gas is introduced to catalytic
hydroconversion reactor 310, together with hydrogen (or
hydrogen-rich gas) and optionally also with steam. Hydrogen
reactively deoxygenates the pyrolysis gas components to generate a
mixture of lighter and heavier hydrocarbons by hydrodeoxygenation
and decarboxylation reactions. Hydrogen and steam act to crack
larger molecules, and to inhibit coking. The reactor effluent is
provided to a first separator 321 from which a liquid fraction of
heavier hydrocarbons is delivered by conduit 322 as a first liquid
hydrocarbon product for further processing and use as desired.
[0100] The overhead fraction from first separator 321 is cooled by
heat recovery unit 330 to generate steam or preheat water upstream
of second separator 331 in which water is condensed and separated
from a liquid fraction of gasoline range hydrocarbons which is
delivered as a second liquid hydrocarbon product by conduit 332 for
further processing and use as desired. The overhead fraction of
gases and vapours from second separator 331 contains H.sub.2, CO,
CO.sub.2, CH.sub.4 and other light hydrocarbons along with some
water vapour. This fraction is reheated and admitted to sorption
enhanced reactor 314, optionally together with a portion of the
cleaned pyrolysis gas from catalyst poison removal section 318 as
controlled by valve 340 in conduit 341.
[0101] Carbonation of CaO in sorption enhanced reactor 314 removes
CO.sub.2 and also CO by water gas shift. Light hydrocarbons are
preferentially prereformed so that the product of sorption enhanced
reactor 314 will be mostly hydrogen with methane as the main
residual carbon-containing compound. After clean-up and cooling of
this product gas mixture from reactor 314, gas separation system 10
separates substantially purified methane into SNG product delivery
conduit 11, and a hydrogen-enriched recycle stream into conduit 12
and back to the hydropyrolysis reactor 304.
[0102] The gas separation system 10 may be operated to deliver a
sufficient amount of hydrogen to the hydropyrolysis reactor and a
significant amount of methane, with more methane production
feasible if less liquid hydrocarbons are produced. In the absence
of supplemental hydrogen imported to the process, approximately
half the carbon in the feed biomass may be converted to product
hydrocarbons (including heavier liquid hydrocarbons in the first
product, gasoline range hydrocarbons in the second product, and
product methane as a third product). The balance of the carbon is
discharged as char or CO.sub.2. Higher carbon conversion can be
achieved with the addition of imported hydrogen.
[0103] The product split between methane and liquid hydrocarbons
can be varied operationally by adjusting gas separation unit 10 so
that more or less methane is delivered. With lower production of
methane, more recycle hydrogen is available to the hydropyrolysis
and hydroconversion reactors so that more liquid hydrocarbons are
produced.
[0104] Production of liquid hydrocarbons can be maximized by
turning off the delivery of product methane. In one embodiment of
the invention, the gas separation system 10 is removed so that the
entire product effluent of sorption enhanced reactor 314 is
delivered to hydropyrolysis reactor 304, while liquid hydrocarbon
delivery of the first and second products is accordingly augmented.
Reactor 314 is then operating as a sorption enhanced steam
reformer, with several advantages including (1) lower temperature
operation than a conventional steam reformer, (2) convenient direct
use of char combustion for regenerating the sorbent, (3) integrated
water gas shift and CO.sub.2 removal, and (4) scavenging of any
alkali and chloride impurities in the recycle gas by the lime
sorbent.
[0105] Regenerator reactor 7 and sorption enhanced reactor 314
comprise a coupled reactor pair for the working reaction and for
regeneration of the sorbent and catalyst. A catalyst regeneration
reactor 330 is also provided for decoking catalyst from
hydroconversion reactor 310.
[0106] A portion of compressed air from compressor 42 and preheater
15 is provided to pyrolysis media heater 315 for combustion of char
to heat the media, with flue gas heat being recovered in steam. The
remainder of the compressed air from compressor 42 and preheater 15
is provided optionally with steam to regeneration reactors 7 and
330 to burn coke off the catalysts and decarbonate the CaCO.sub.3
formed in sorption enhanced reactor 314. Heat recovery steam
generators 8, 319 and 350 deliver steam to sorption enhanced
reactor 314, or to regeneration reactors 330 and 7 as needed.
[0107] FIG. 9 shows an embodiment 400, in which a hydrogasification
system similar to embodiment 1 is coupled to a solid oxide fuel
cell (SOFC) 410 for generation of electricity. The SOFC has a solid
oxide electrolyte 412 between a cathode chamber 413 and an anode
chamber 414. The cathode chamber has inlet port 415 and outlet port
416, and the anode chamber has inlet port 417 and outlet port 418.
The anode chamber includes an internal reforming catalyst (which
may be comprised within the anode itself) to convert methane and
steam to hydrogen and carbon oxides CO and CO.sub.2 under SOFC
operating conditions at elevated temperatures in the range of about
600.degree. C. to about 800.degree. C.
[0108] A portion of the compressed air (or compressed
oxygen-enriched air) from air compression unit 16 is heated in
thermal recuperator 422, and fed to cathode inlet port 415.
Vitiated cathode gas is discharged from port 416 and exhausted
through recuperator 420 which recovers sensible heat from this
gas.
[0109] A hot gas clean-up section 430 is provided to remove solid
particulate, alkalis and any chloride or sulphur compounds that
have not been captured by the sorbent. The hot gas clean-up section
430 may include cyclones, filters (metal fabric, ceramic candles or
precoat filters), and chemical sorbents as necessary to capture the
alkalis and any other detrimental components. Captured solids and
spent sorbents will be released from discharge conduit 431.
[0110] FIG. 10 is a graph of methane conversion, methane
concentration, hydrogen concentration, and the ratio of hydrogen
output to hydrogen input (H.sub.2out/H.sub.2in) from the
hydrogasification reactor of the invention, versus the ratio of
carbon carbonated on the sorbent to carbon content of the biomass
feed to the process.
[0111] These correlations were derived for the case of an AEM
process operating with CaO sorbent at a temperature of 600.degree.
C. and a pressure of 10 bara, with 1.0 molecules of hydrogen and
0.6 molecules of water vapour (including initial water content
within the biomass) provided per atom of carbon in the original
woody biomass feed. Thermodynamic equilibrium was assumed for the
water gas shift, steam reforming and methanation reactions, with
methane the only hydrocarbon molecule participating in these
post-pyrolysis reactions. Char and coke deposition was assumed to
consume about 21% of feed biomass carbon.
[0112] Modeling runs were performed for different values of
sorption uptake of carbon, shown as fractional carbonation of the
original biomass carbon. Maximum fractional carbonation was found
to be 0.4491, at which condition the partial pressure of CO.sub.2
is at equilibrium with a mixture of CaO and CaCO.sub.3. At a
fractional carbonation of 0.370, the hydrogen output is equal to
the amount of hydrogen input, thus defining an ideal
self-sustaining condition without excess hydrogen generated or any
external supplemental supply of hydrogen. With allowance for
imperfect separation of product methane and recycle hydrogen, the
practicable operating condition for self-sustaining hydrogen
generation (without supplemental hydrogen supply from any external
source) in this example will require fractional carbonation greater
than 0.37, and of the order of 0.4.
[0113] The above example shows that high purity methane can be
produced by the sorption enhanced methanation method according to
the invention, with methane the predominantly surviving carbon
compound after nearly complete removal of CO.sub.2 and CO. This
example contrasts dramatically with the related and well known
process of sorption enhanced steam reforming of methane, where
methane is nearly completely extinguished along with CO.sub.2 and
CO in order to achieve hydrogen production with highest possible
conversion.
INDUSTRIAL APPLICABILITY
[0114] Disclosed embodiments of the method and system are useful
for high efficiency conversion of biomass, including forestry
residues (including those generated by logging, thinning, and
wildfire prevention fuel load reduction activities) and sawmill
waste into SNG, either as a fuel commodity or for high efficiency
generation of electrical power. Disclosed embodiments provide
advantageous integrations with gas turbines and/or solid oxide fuel
cells. A portion of the biomass may also be converted into heavier
and lighter hydrocarbon liquids.
[0115] Disclosed embodiments of the system may be used at
industrial scale limited only by transportation distances for
collection of biomass feedstock, or at smaller scale in rural or
remote areas for combined generation of heat, high heating value
fuel gas and electricity. At the smallest scale, the system may be
used for residential heating, methane fuel production and
electrical power generation through a solid oxide fuel cell or
other energy converter consuming a portion of the product
methane.
[0116] In view of the many possible embodiments to which the
principles of the disclosed invention may be applied, it should be
recognized that the illustrated embodiments are only preferred
examples of the invention and should not be taken as limiting the
scope of the invention. Rather, the scope of the invention is
defined by the following claims. We therefore claim as our
invention all that comes within the scope and spirit of these
claims.
* * * * *