U.S. patent application number 11/563243 was filed with the patent office on 2008-05-01 for synthetic fuel production methods and apparatuses.
This patent application is currently assigned to Battelle Energy Alliance, LLC. Invention is credited to Robert S. Cherry, Richard A. Wood.
Application Number | 20080098654 11/563243 |
Document ID | / |
Family ID | 39468261 |
Filed Date | 2008-05-01 |
United States Patent
Application |
20080098654 |
Kind Code |
A1 |
Cherry; Robert S. ; et
al. |
May 1, 2008 |
SYNTHETIC FUEL PRODUCTION METHODS AND APPARATUSES
Abstract
Carbon-containing tail gases and pollutants in a coal-to-liquid
hydrocarbon production process, or other liquid fuel production
process, may be reacted to produce additional synthesis gas which
may be used to produce liquid fuels and hydrocarbons or which may
be recycled within the liquid fuel production process to improve
conversion of carbon to liquid fuels or hydrocarbons.
Inventors: |
Cherry; Robert S.; (Idaho
Falls, ID) ; Wood; Richard A.; (Idaho Falls,
ID) |
Correspondence
Address: |
BATTELLE ENERGY ALLIANCE, LLC
P.O. BOX 1625
IDAHO FALLS
ID
83415-3899
US
|
Assignee: |
Battelle Energy Alliance,
LLC
Idaho Falls
ID
|
Family ID: |
39468261 |
Appl. No.: |
11/563243 |
Filed: |
November 27, 2006 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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11552604 |
Oct 25, 2006 |
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11563243 |
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Current U.S.
Class: |
48/101 ;
48/210 |
Current CPC
Class: |
C10G 1/002 20130101 |
Class at
Publication: |
48/101 ;
48/210 |
International
Class: |
C10B 1/00 20060101
C10B001/00 |
Goverment Interests
GOVERNMENT RIGHTS
[0002] The United States Government has certain rights in this
invention pursuant to Contract No. DE-AC07-05-ID14517 between the
United States Department of Energy and Battelle Energy Alliance,
LLC.
Claims
1. A liquid fuel production system, comprising: at least one
gasification process apparatus configured to produce a synthesis
gas; at least one gas cleanup process configured to remove carbon
dioxide from the synthesis gas; at least one synthesis gas
conversion process apparatus configured to receive at least a
portion of the synthesis gas after removal of at least a portion of
the carbon dioxide therefrom and to produce a carbon-containing
tail gas; and at least one reactor configured to receive at least a
portion of the carbon dioxide removed from the synthesis gas by the
gas cleanup process and configured to receive the carbon-containing
tail gas from the at least one synthesis gas conversion process
apparatus.
2. The liquid fuel production system of claim 1, wherein the at
least one gasification process apparatus comprises a gasification
unit selected from the group consisting of an entrained flow
gasifier, a counter-current fixed bed gasifier, a co-current fixed
bed gasifier, and a fluid bed gasifier.
3. The liquid fuel production system of claim 1, wherein the at
least one synthesis gas conversion process apparatus comprises a
Fischer-Tropsch process apparatus.
4. The liquid fuel production system of claim 1, wherein the at
least one reactor further comprises a reactor configured to react
the at least a portion of the carbon dioxide with at least a
portion of the carbon-containing tail gas.
5. The liquid fuel production system of claim 1, further comprising
at least one product recycle stream configured to deliver a recycle
synthesis gas formed in the at least one reactor to the at least
one gas cleanup process.
6. The liquid fuel production system of claim 1, further comprising
at least one product recycle stream configured to deliver a recycle
synthesis gas formed in the at least one reactor to the at least
one synthesis gas conversion process.
7. The liquid fuel production system of claim 1, further comprising
at least one product recycle stream configured to recycle a
synthesis gas formed in the at least one reactor to the at least
one gasification process apparatus.
8. The liquid fuel production system of claim 1, further comprising
a steam source configured to mix steam with the carbon dioxide
removed from the gas cleanup process.
9. The liquid fuel production system of claim 1, further comprising
a steam source configured to mix steam with at least a portion of
the carbon-containing tail gas from the at least one synthesis gas
conversion process.
10. The liquid fuel production system of claim 1, further
comprising a steam source configured to mix steam with at least a
portion of the carbon dioxide removed from the gas cleanup process
and at least a portion of the carbon-containing tail gas from the
at least one synthesis gas conversion process.
11. A liquid fuel production system, comprising: at least one
gasification process apparatus configured to produce a synthesis
gas; at least one gas cleanup process configured to remove carbon
dioxide from the synthesis gas; at least one synthesis gas
conversion process apparatus configured to receive at least a
portion of the synthesis gas after removal of at least a portion of
the carbon dioxide therefrom and to produce a carbon-containing
tail gas; at least one steam source configured to combine steam
with at least one of the carbon dioxide removed from the synthesis
gas and the carbon-containing tail gas; and at least one reactor
configured to receive at least a portion of the carbon dioxide
removed from the synthesis gas, at least a portion of the steam,
and at least a portion of the carbon-containing tail gas.
12. The liquid fuel production system of claim 11, further
comprising at least one product recycle stream configured to
deliver a recycle synthesis gas formed in the at least one reactor
to the at least one synthesis gas conversion process apparatus.
13. The liquid fuel production system of claim 11, further
comprising at least one product recycle stream configured to
combine a recycle synthesis gas formed in the at least one reactor
with the synthesis gas produced in the at least one gasification
process apparatus.
14. The liquid fuel production system of claim 11, further
comprising at least one product recycle stream configured to
recycle a synthesis gas formed in the at least one reactor to the
at least one gasification process apparatus.
15. A method for converting a carbon-containing fuel to liquid
fuel, comprising: providing a carbon-containing fuel supply;
gasifying at least a portion of the carbon-containing fuel supply
to produce a synthesis gas; removing carbon dioxide from the
synthesis gas; converting the synthesis gas into liquid
hydrocarbons and a tail gas using a synthesis gas conversion
process; and reacting at least a portion of the carbon dioxide with
at least a portion of the tail gas to produce a recycle synthesis
gas product.
16. The method of claim 15, wherein providing a carbon-containing
fuel supply comprises providing at least one carbon-containing fuel
selected from the group consisting of coal, oil shale, biomass,
refuse, waste materials, natural gas, lignite, and mixtures
thereof.
17. The method of claim 15, wherein gasifying at least a portion of
the carbon-containing fuel supply comprises gasifying the
carbon-containing fuel supply in a gasifier selected from the group
consisting of an entrained flow gasifier, a counter-current fixed
bed gasifier, a co-current fixed bed gasifier, and a fluid bed
gasifier.
18. The method of claim 15, wherein removing carbon dioxide from
the synthesis gas further comprises: providing a gas cleanup
process; feeding at least a portion of the produced synthesis gas
to the gas cleanup process; and removing carbon dioxide from the
synthesis gas in the gas cleanup process.
19. The method of claim 15, wherein converting the synthesis gas
into liquid hydrocarbons and a tail gas using a synthesis gas
conversion process comprises converting the synthesis gas into
liquid hydrocarbons and a tail gas in a Fischer-Tropsch
process.
20. The method of claim 15, further comprising combining the
recycle synthesis gas product with the produced synthesis gas.
21. The method of claim 15, further comprising feeding the recycle
synthesis gas product to the synthesis gas conversion process.
22. The method of claim 15, further comprising combining the carbon
dioxide with steam.
23. The method of claim 15, further comprising combining the tail
gas with steam.
24. The method of claim 15, wherein reacting at least a portion of
the carbon dioxide with at least a portion of the tail gas to
produce a recycle synthesis gas product further comprises:
combining the carbon dioxide with steam; combining the tail gas
with steam; and reacting the carbon dioxide combined with steam
with the tail gas combined with steam to produce carbon monoxide
and hydrogen.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application is a continuation-in-part application of
U.S. patent application Ser. No. 11/552,604 filed on Oct. 25, 2006,
and entitled "SYNTHETIC FUEL PRODUCTION USING COAL AND NUCLEAR
ENERGY," the disclosure of which is incorporated herein by
reference in its entirety.
BACKGROUND OF THE INVENTION
[0003] 1. Field of the Invention
[0004] The present invention relates to processes and systems for
converting carbonaceous feedstocks to liquid hydrocarbons and
liquid fuel products and, more particularly, to the use of
alternative energy sources and recycling processes to provide
improved recovery in coal-to-liquid or carbon-to-liquid processes
and systems.
[0005] 2. State of the Art
[0006] Processes for producing liquid fuel products from coal are
well known. One of the more common processes involving the
conversion of coal to liquid hydrocarbon fuels involves
Fischer-Tropsch processes whereby synthesis gas, or syngas, is
converted into liquid fuel products of various forms. Synthesis gas
for use in the Fischer-Tropsch process may be produced by the
gasification of coal which produces carbon monoxide and
hydrogen.
[0007] An example of a conventional coal-to-liquid hydrocarbon
process is illustrated in the process flow diagram of FIG. 1. The
coal-to-liquid hydrocarbon (CTL) process 100 may include a number
of sub-processes occurring within the CTL process 100. For example,
a conventional CTL process 100 may include a coal gasification
process 110, a gas and heat recovery process 120, a gas cleanup
process 130, a Fischer-Tropsch process 160, and a heat recovery and
power generation process 190. Each of the sub-processes illustrated
in FIG. 1 is separated by dashed lines.
[0008] The coal gasification process 110 of the CTL process 100
includes a dryer 112, a pulverizer 114, an entrained flow gasifier
116, and an air separation unit 118. Coal 111 for use in the coal
gasification process 110 is fed to one or more dryers 112 to reduce
moisture in the coal 111. Moisture extracted from the coal 111 may
be discharged from the dryers 112. A dryer 112 may include a heat
exchanger or other conventional drying process typically used with
CTL processes 100. The dried coal 113 is fed to a pulverizer 114
where the dried coal 113 is pulverized, crushed, or otherwise
reduced to a sufficient size for coal gasification. The pulverized
coal 115 is fed to the entrained flow gasifier 116 where the coal
is gasified. Air 119 fed to the air separation unit 118, such as a
cryogenic air separation unit, is converted into nitrogen (N.sub.2)
and oxygen (O.sub.2). The nitrogen is purged as nitrogen stream
118b while the oxygen stream 118a is fed to the entrained flow
gasifier 116.
[0009] The pulverized coal 115 fed to the entrained flow gasifier
116 is gasified with oxygen from the oxygen stream 118a in the
presence of steam 50 fed to the entrained flow gasifier 116. Boiler
feed water (BFW) 52 may also be fed to the entrained flow gasifier
to absorb heat produced in the gasification process, forming a
medium pressure steam (MPS) 54 which may be removed from the
entrained flow gasifier 116 and used elsewhere in the CTL process
100. The combustion, pyrolysis, and gasification of the pulverized
coal 115 fed to the entrained flow gasifier 116 produces a syngas
product 116a and a slag 116b. The syngas product 116a is removed
from the entrained flow gasifier 116 and the coal gasification
process 110 and is fed to a gas and heat recovery process 120. Slag
116b is removed from the entrained flow gasifier 116 and is
disposed of or otherwise utilized according to conventional
methods.
[0010] The syngas product 116a from the entrained flow gasifier 116
includes carbon monoxide (CO), hydrogen (H.sub.2), and other gas
products. The hot syngas product 116a is fed to a syngas cooler 122
in the gas and heat recovery process 120. The syngas cooler 122
cools the hot syngas product 116a and produces a cool syngas
product 123 which is withdrawn from the syngas cooler 122. The cool
syngas product 123 is then fed to a gas cleanup process 130.
[0011] The hot syngas product 116a fed to the syngas cooler 122 may
also be combined with a quench gas 143 from the gas cleanup process
130, the quench gas having been fed through one or more compressors
124.
[0012] Boiler feed water 52 may also be fed to the syngas cooler
122. The boiler feed water 52 absorbs heat within the syngas cooler
122 producing steam, such as high pressure steam 56 and medium
pressure steam 54. High pressure steam 56 produced in the syngas
cooler 122 is discharged. High pressure steam 56 may also be fed to
the sour shift reactor 138 of the gas cleanup process 130. Medium
pressure steam 54 produced in the syngas cooler 122 may be
recovered and used elsewhere in the CTL process 100.
[0013] The gas cleanup process 130 is used to remove pollutants and
other unwanted products from the cool syngas product 123 fed to the
gas cleanup process 130. The gas cleanup process 130 includes a
cyclone 132, a water scrubber 134, a black water system 136, a sour
shift reactor 138, a heat exchanger 140, a condenser 142, and an
activated carbon bed 144. The gas cleanup process 130 also includes
equipment for removing hydrogen sulfide (H.sub.2S) and carbon
dioxide (CO.sub.2) from synthesis gas.
[0014] Cool syngas product 123 fed to the gas cleanup process 130
is fed to a cyclone 132 to remove flash 133 and other particulates
from the cool syngas product 123. The cool syngas product 123 is
then fed to a water scrubber 134 with water 60. The water scrubber
134 removes pollutants and other impurities from the cool syngas
product 123 and discharges the removed pollutants and other
impurities with water 60 in a waste water stream 134a. A scrubbed
syngas product 135 is split into a first scrubbed syngas stream
135a that is fed to the sour shift reactor 138 and a second
scrubbed syngas stream 135b that bypasses the sour shift reactor
138 and is combined with the shifted syngas product 138a from the
sour shift reactor 138. The first scrubbed syngas stream 135a fed
to the sour shift reactor 138 is combined with high pressure steam
56 fed to the sour shift reactor 138 to produce desired ratios of
hydrogen and carbon monoxide for the syngas being produced. The
shift of the hydrogen and carbon monoxide ratios in the shifted
syngas product 138a from the sour shift reactor 138 may be
manipulated such that the combination of the shifted syngas product
138a with the second scrubbed syngas product 135b produces a syngas
product 139 having a desired ratio of hydrogen and carbon monoxide
for the Fischer-Tropsch process 160.
[0015] The waste water stream 134a is fed to a black water
treatment system 136 for treatment of the waste water stream 134a
according to conventional methods.
[0016] The syngas product 139 is fed to a heat exchanger 140 that
cools the syngas product 139. Boiler feed water 52 fed to the heat
exchanger 140 may be converted into medium pressure steam 54, which
may be used in other portions of the CTL process 100.
[0017] The cooled syngas product 141 from the heat exchanger 140 is
fed to a condenser 142 where water 60 in the cooled syngas product
141 is condensed and removed from the cooled syngas product 141.
The water 60 may be fed to the water scrubber 134 in the gas
cleanup process 130.
[0018] The syngas product 143 from the condenser 142 is fed to an
activated carbon bed 144. The activated carbon bed 144 removes
unwanted mercury pollutants from the syngas product 143. A portion
of the syngas product 143 exiting the activated carbon bed 144 may
be removed and fed to the compressor 124 of the gas and heat
recovery process 120 and combined with the syngas product 116a as
feed stock to the syngas cooler 122. The remainder of the syngas
product 143 is fed to a Rectisol process 146 to further remove
hydrogen sulfide (H.sub.2S) and carbon dioxide (CO.sub.2) from the
syngas product 143.
[0019] The Rectisol process 146 removes hydrogen sulfide and carbon
dioxide from the syngas product 143, producing a first product
stream 146a containing hydrogen sulfide and carbon dioxide, a
second product stream 146b containing carbon dioxide, a purge gas
146c, and a syngas product stream 147.
[0020] The first product stream 146a can be fed to a Claus process
148 for removal of sulfur 148a from the gaseous hydrogen sulfide in
the first product stream 146a. The Claus tail gases 148b are fed to
a SCOT process 150 for further treatment before being discharged as
a SCOT process purge gas 150a.
[0021] The second product stream 146b of carbon dioxide is
compressed in a first compressor 152 and then fed to a triethylene
glycol (TEG) dehydration process 154 where water is removed from
the second product stream 146b. Water removed from the second
product stream 146b may be used elsewhere in the CTL process 100.
Carbon dioxide gas from the TEG process 154 is fed to a compressor
156 where it is cooled to form liquid carbon dioxide 157. The
liquid carbon dioxide 157 is pumped to a storage tank or other
process for further use.
[0022] The purge gas 146c from the Rectisol process 146 is released
into the environment. The Rectisol process 146, Claus process 148,
SCOT process 150, and TEG dehydration process 154 are well known
processes conventionally used to remove sulfur and carbon dioxide
pollutants from CTL processes 100.
[0023] The syngas product stream 147 is fed to a Fischer-Tropsch
process 160 for conversion of the syngas product stream 147 into
liquid fuel products. The Fischer-Tropsch process 160 illustrated
in FIG. 1 includes a first Fischer-Tropsch reactor 162, a first
heat exchanger 164, a first separation unit 166, a compressor 168,
a second Fischer-Tropsch reactor 172, a second heat exchanger 174,
a second separation unit 176, a hydrocracker 170, a hydrogen
separation membrane 178, a second compressor 180, a tank 182, and
distillation columns 184.
[0024] The syngas product stream 147 from the gas cleanup process
130 contains hydrogen (H.sub.2) and carbon monoxide (CO). In the
Fischer-Tropsch process 160, the syngas product stream 147 is fed
to the first Fischer-Tropsch reactor 162 where the hydrogen and
carbon monoxide in the syngas product stream 147 are converted into
liquid fuel products through a catalysis reaction, such as Reaction
1:
(2n+1)H.sub.2+nCO.fwdarw.C.sub.nH.sub.2n+2+nH.sub.2O (1),
where n may be between about 1 and about 42, although n may also be
greater than 42. For example, for light hydrocarbons n may be
between about 1 and about 7, for intermediate hydrocarbons n may be
from about 8 to about 13, and for heavy hydrocarbons n may be above
about 14.
[0025] A first hydrocarbon stream 163 containing both liquid fuel
products and gas from the first Fischer-Tropsch reactor 162 is
cooled in the first heat exchanger 164. Boiler feed water 52 fed to
the first heat exchanger 164 absorbs heat from the first
hydrocarbon stream 163, producing medium pressure steam 54 that is
purged for use in other processes. The cooled first hydrocarbon
stream 163 is fed to the first separation unit 166 where various
constituents of the first-hydrocarbon stream 163 are separated.
Syngas 167 remaining in the first hydrocarbon stream 163 is
separated by the first separation unit 166 and purged to be fed to
the second Fischer-Tropsch reactor 172. The liquid fuel products in
the first hydrocarbon stream 163 are separated by the first
separation unit 166 into two hydrocarbon streams: a first light
hydrocarbon product 166a containing intermediate distillates and
light hydrocarbons, and a first heavy hydrocarbon product 166b
containing heavy hydrocarbons. The first separation unit 166 also
removes water 60 from the first hydrocarbon stream 163 and purges
the water 60 from the other products.
[0026] Syngas 167 from the first separation unit 166 is compressed
in the compressor 168 and is then fed to the second Fischer-Tropsch
reactor 172 where the syngas 167 is catalytically reacted to
convert the hydrogen and carbon monoxide in the syngas 167 into
liquid fuel products. For example, the syngas 167 may be converted
into liquid fuel products in accordance with Reaction 1. A second
hydrocarbon stream 173 from the second Fischer-Tropsch reactor 172
is cooled in the second heat exchanger 174 and fed to the second
separation unit 176. Boiler feed water 52 fed to the second heat
exchanger 174 absorbs heat from the second hydrocarbon stream 173,
producing medium pressure steam 54 that is purged for use in other
processes or other parts of the CTL process 100.
[0027] The second separation unit 176 separates the second
hydrocarbon stream 173 into its various constituents. Water 60
separated from the second hydrocarbon stream 173 is purged from the
second separation unit 176 for use elsewhere. Liquid fuel products
in the second hydrocarbon stream 173 are separated into two
hydrocarbon streams: a second light hydrocarbon product 176a
containing intermediate distillates and light hydrocarbons, and a
second heavy hydrocarbon product 176b containing heavy
hydrocarbons. The tail gases 177 separated from the second
hydrocarbon stream 173 in the second separation unit 176 are fed to
the hydrogen separation membrane 178 where the hydrogen (H.sub.2)
179 in the tail gases 177 is removed.
[0028] Heavy hydrocarbons produced in the Fischer-Tropsch process
160 are converted to light hydrocarbons or liquid fuel products in
the hydrocracker 170. The first heavy hydrocarbon product 166b and
the second heavy hydrocarbon product 176b produced by the
Fischer-Tropsch reactors are mixed together to form a heavy
hydrocarbon stream 169 that is fed to the hydrocracker 170. Heavy
hydrocarbons 185 from the distillation column 184 are also fed to
the hydrocracker 170. Hydrogen 179, separated from the tail gases
177 by the hydrogen separation membrane 178, is pressurized or
compressed in compressor 180 before being fed to the hydrocracker
170 to facilitate the hydrocracking of the heavy hydrocarbons to
produce a hydrocarbon product 171 of lighter hydrocarbons or liquid
fuel products from the hydrocracker 170.
[0029] The hydrocarbon product 171 is combined with the second
light hydrocarbon product 176a and then with the first light
hydrocarbon product 166a and mixed in tank 182 to form a light
hydrocarbon product 183. The light hydrocarbon product 183 is fed
to the distillation column 184. Within the distillation column 184,
the light hydrocarbon product 183 produced by the Fischer-Tropsch
process 160 is distilled into naphtha products 186 and diesel
products 187. Heavy hydrocarbons 185 produced in the distillation
column 184 are removed from the distillation column 184 and fed to
the hydrocracker 170. Purge gases 188 from the distillation column
184 may be combined with the tail gases 177 and fed to the hydrogen
separation membrane 178 for separation of hydrogen from the purge
gases 188.
[0030] The CTL process 100 may also include a heat recovery and
power generation process 190. The heat recovery and power
generation process 190 converts heat recovered from the CTL process
100 into power. Recovered steam 58, such as high pressure steam 56
and medium pressure steam 54, collected in the CTL process 100 is
fed to a heat recovery steam generator 194 along with boiler feed
water 52 and air 119. Tail gases 191 from the hydrogen separation
membrane 178 are combined with air 119 and burned in a gas turbine
192 connected to a generator to produce electricity. Exhaust gases
193 from the gas turbine 192 are fed to the heat recovery steam
generator 194 to further heat the boiler feed water 52 and
recovered steam 58 fed to the heat recovery steam generator 194.
Superheated steam 195 produced in the heat recovery steam generator
194 is fed to a condensing steam turbine 196 which produces
electricity from the expansion and cooling of the superheated steam
195. The water produced in the condensing steam turbine 196 is fed
to a pump 199 and pumped throughout the CTL process 100 to be used
as boiler feed water 52.
[0031] The exhaust gases 193 are cooled in the heat recovery steam
generator 194 and are then fed to a stack 198. The gases exiting
the stack may be further treated or released into the
environment.
[0032] Although CTL processes 100 such as the one illustrated in
FIG. 1 may be used to produce liquid hydrocarbons and liquid fuel
products from synthesis gas produced by the gasification of coal,
such processes often produce a larger amount of pollutants than do
conventional petroleum extraction and refining processes associated
with liquid fuel production. One of the most prevalent pollutants
produced by coal gasification is carbon dioxide (CO.sub.2).
Increased production of synthesis gases from coal gasification to
supply Fischer-Tropsch processes with sufficient synthesis gas to
produce liquid hydrocarbons and liquid fuel products would result
in the unwanted increased production of carbon dioxide emissions.
Proposals to counter the increased carbon dioxide emissions
resulting from coal gasification have included proposals to
sequester the carbon dioxide or otherwise convert the carbon
dioxide produced in such a process prior to release into the
environment. Carbon dioxide sequestration processes are expensive
and add additional costs to liquid hydrocarbon production
processes. Other proposed alternatives to encourage sequestration
or conversion of carbon dioxide to a non-pollutant have also been
made, including proposals to tax carbon dioxide emissions from coal
gasification and Fischer-Tropsch processes.
[0033] Furthermore, coal gasification processes tend to be fairly
inefficient. For example, a CTL process 100 such as that
illustrated in FIG. 1 may convert about thirty-percent of the
carbon contained in the coal fed to the process to liquid
hydrocarbons or liquid fuel products. The remaining seventy-percent
of the carbon in the coal is converted to carbon dioxide, other
pollutants, or solid wastes that must be disposed.
[0034] Therefore, it would be desirable to improve the efficiency
of coal-to-liquid hydrocarbon production process and to increase
the conversion of carbon obtained from coal to liquid fuel
products. It would also be desirable to decrease the carbon dioxide
emissions of coal-to-liquid hydrocarbon production processes.
BRIEF SUMMARY OF THE INVENTION
[0035] According to embodiments of the invention, the conversion of
carbon to liquid fuel products in a coal-to-liquid hydrocarbon
production process may be improved by modifying a conventional
coal-to-liquid hydrocarbon production process or by incorporating
the modifications into new process plants. The modifications to a
coal-to-liquid hydrocarbon production process facilitate the
conversion of carbon to liquid fuel products and reduce the amount
of carbon-based pollutants produced by a coal-to-liquid hydrocarbon
production process.
[0036] In some embodiments of the invention, a water-splitting
process, such as an electrolysis or thermochemical process, for
producing oxygen may be integrated with a liquid fuel production
process, such as a coal-to-liquid hydrocarbon production process,
or may be configured to supply oxygen to a liquid fuel production
process. The oxygen may be used in the liquid fuel production
process to gasify coal in the production of a synthesis gas
containing hydrogen and carbon monoxide. The water-splitting
process may produce oxygen from water utilizing conventional
electrolysis processes. The power or heat required by the
water-splitting process to produce oxygen from water may be
supplied from a nuclear power source. The use of a nuclear power
source to produce electricity or power to supply to the
water-splitting process decreases the production of pollutants
associated with conventional coal-fired electricity generation
operations. The resulting liquid fuel production process therefore
produces fewer pollutants. In addition, the use of a
water-splitting process reduces the need for air separation units
conventionally used with gasification processes to produce oxygen,
reducing the equipment and operating costs associated with the
production of liquid fuels, such as by the gasification of
coal.
[0037] In other embodiments of the invention, the water-splitting
process may also produce hydrogen. The water-splitting process may
be configured to supply the produced hydrogen to the liquid fuel
production process. In particular, hydrogen produced by the
water-splitting process may be mixed with synthesis gas produced in
the liquid fuel production process to achieve a desired ratio of
hydrogen to carbon monoxide in the synthesis gas. The hydrogen
produced by the water-splitting process may also be used to
facilitate hydrocracking of heavy hydrocarbons or liquid fuel
products produced from the synthesis gas generated in the liquid
fuel production process.
[0038] The incorporation of a hydrogen-producing water-splitting
process with a liquid fuel production process also allows for the
reduction of equipment needed in a liquid fuel production process.
The availability of hydrogen to mix with synthesis gas produced in
the process reduces or eliminates the need for shift reactions
within the liquid fuel production process. Therefore, equipment
associated with such shift reactions may be made smaller or removed
from the process, reducing the overall equipment and operational
costs of the process.
[0039] According to still other embodiments of the invention,
pollutant gases removed from the synthesis gases produced in a
liquid fuel production process may be recycled to a coal
gasification process or other synthesis gas production process.
Carbon-containing compounds and pollutants, such as carbon dioxide,
carbon monoxide, methane, alkanes, alkenes, alcohols, aldehydes, or
other species, produced in a liquid fuel production process may be
recycled to a coal gasification process, for example, where the
carbon-containing pollutants may be further reacted to produce
additional synthesis gas. The production of additional synthesis
gas from the carbon-containing pollutants improves the yield of
liquid hydrocarbons and liquid fuel products produced in the
process while reducing the amount of carbon-containing pollutants
produced by the process.
[0040] According to other particular embodiments of the invention,
tail gases from a Fischer-Tropsch process associated with a liquid
fuel production process, such as a coal-to-liquid hydrocarbon
production process, may be recycled to generate additional
synthesis gas in the process. In some embodiments, the tail gases
may be recycled because they are not needed to supply energy due to
the availability of an alternative energy source, such as a nuclear
reactor.
[0041] According to other embodiments of the invention, tail gases
from a Fischer-Tropsch process associated with a liquid fuel
production process may be reacted with carbon dioxide removed from
a synthesis gas produced by a carbon-containing fuel gasification
process. The reaction of the tail gases with the carbon dioxide may
produce carbon monoxide and hydrogen which may be recycled and
combined with synthesis gas produced by a gasification process,
recycled and combined with a cleaned synthesis gas, or recycled to
a Fischer-Tropsch process or other liquid fuel production process.
In some embodiments of the invention, steam may be combined with
the tail gas, with the carbon dioxide, or with both the tail gas
and carbon dioxide prior to or during the reaction of the tail gas
and carbon dioxide. The inclusion of steam in the reaction of the
carbon dioxide and the tail gas may improve the production of
carbon monoxide and hydrogen or may alter the amounts of carbon
monoxide and hydrogen produced by the reaction.
[0042] In still other embodiments of the invention, at least a
portion of the reaction product of carbon monoxide and hydrogen
produced by the reaction of tail gases from a liquid fuel
production process may be recycled to a gas cleanup process.
Alternatively, the reaction product may be mixed with a product gas
from a gasification process. The recycling of the carbon monoxide
and hydrogen to the gasification process may improve the conversion
of the carbon in the carbon-containing fuel into useful synthesis
gas products rather than pollutants or unwanted products.
[0043] The liquid fuel production processes of various embodiments
of the invention provide enhanced yields of liquid hydrocarbons and
liquid fuel products per ton of coal or fuel when compared to
conventional processes. In addition, the liquid fuel production
processes of embodiments of the invention reduce the production of
carbon-containing pollutants in the process.
BRIEF DESCRIPTION OF THE DRAWINGS
[0044] While the specification concludes with claims particularly
pointing out and distinctly claiming that which is regarded as the
present invention, this invention can be more readily understood
and appreciated by one of ordinary skill in the art from the
following description of the invention when read in conjunction
with the accompanying drawings in which:
[0045] FIG. 1 illustrates a process flow and system diagram of a
conventional coal-to-liquid hydrocarbon production process;
[0046] FIG. 2 illustrates a process flow and system diagram of a
coal-to-liquid hydrocarbon production process according to certain
embodiments of the invention;
[0047] FIG. 3 illustrates a process flow and system diagram of a
coal-to-liquid hydrocarbon production process according to certain
embodiments of the invention;
[0048] FIG. 4 illustrates a process flow and system diagram of a
coal-to-liquid hydrocarbon production process according to certain
embodiments of the invention;
[0049] FIG. 5 illustrates a process flow and system diagram of a
coal-to-liquid hydrocarbon production process according to certain
embodiments of the invention;
[0050] FIG. 6 illustrates a process flow and system diagram of a
liquid fuel production process according to certain embodiments of
the invention;
[0051] FIG. 7 illustrates a process flow and system diagram of a
liquid fuel production process according to certain embodiments of
the invention; and
[0052] FIG. 8 illustrates a process flow and system diagram of a
liquid fuel production process according to certain embodiments of
the invention.
DETAILED DESCRIPTION OF THE ILLUSTRATED EMBODIMENTS
[0053] According to embodiments of the invention, a nuclear power
source may be integrated with or incorporated into a liquid fuel
production process, such as a coal-to-liquid hydrocarbon production
process, to facilitate the production of hydrocarbons and liquid
fuel products from coal. Although the additional heat produced by a
nuclear power source may not be needed in a conventional
coal-to-liquid hydrocarbon production process, the integration of a
nuclear power source with a coal-to-liquid hydrocarbon production
process, or other liquid fuel production process, facilitates the
use of alternative processes to produce oxygen (O.sub.2) and
hydrogen (H.sub.2), allowing expensive equipment to be removed from
a liquid fuel production process.
[0054] While various embodiments of the invention may be integrated
with liquid fuel production processes, many of the embodiments will
be described with respect to a coal-to-liquid hydrocarbon
production process. It is understood that other liquid fuel
production processes may be substituted for the coal-to-liquid
hydrocarbon production processes described with respect to
particular embodiments of the invention.
[0055] According to certain embodiments of the invention, a nuclear
power source may be configured to provide electric power, heat, or
a combination of electric power and heat to operate a
water-splitting process. The water-splitting process may be used to
generate oxygen and hydrogen from water. Oxygen produced by the
water-splitting process may be substituted for the oxygen produced
by an air separation unit 118 in a conventional CTL process 100
such as the process illustrated in FIG. 1. The alternative source
of oxygen provided by the water-splitting process and nuclear power
source eliminates the need for an air separation unit in a CTL
process 100. Air separation units, such as air separation unit 118
in the conventional CTL process 100 illustrated in FIG. 1, are
often expensive to install and expensive to operate. The use of
oxygen from a water-splitting process operated with nuclear power
may therefore decrease the costs associated with the operation of a
coal-to-liquid hydrocarbon production process.
[0056] An example of a coal-to-liquid hydrocarbon production
process 200 utilizing oxygen produced by a water-splitting process
300 rather than by an air separation unit is illustrated in FIG. 2.
As with a conventional CTL process 100, coal-to-liquid hydrocarbon
production processes 200 may include sub-processes such as a coal
gasification process 210, a gas and heat recovery process 220, a
gas cleanup process 230, a Fischer-Tropsch process 260, and a heat
recovery and power generation process 290. The sub-processes of the
coal-to-liquid hydrocarbon production process 200 which do not
differ from convention CTL process 100 sub-processes are
illustrated as sub-process blocks in FIG. 2.
[0057] The coal-to-liquid hydrocarbon production process 200
illustrated in FIG. 2 may also include a water-splitting process
300. For example, a water-splitting process 300 may include an
electrolysis process or a thermochemical water-splitting process.
While various water-splitting processes may be used with various
embodiments of the invention, certain embodiments are described
with respect to the use of an electrolysis process. It is
understood that other water-splitting processes may be used in
place of or in combination with an electrolysis process according
to various embodiments of the invention. For example, a
water-splitting process 300 according to embodiments of the
invention may include one or more nuclear power sources 302, one or
more electrolyzers 304, one or more oxygen compressors 312, and one
or more hydrogen compressors 314.
[0058] The one or more nuclear power sources 302 may include any
source of power resulting from nuclear energy. For example,
multiple high-temperature nuclear reactors may be used to produce
electricity 303 capable of operating one or more electrolyzers 304
to produce oxygen 308 and hydrogen 310 from water 306. The oxygen
308 may be compressed by one or more compressors 312 and fed to the
entrained flow gasifier 216 of the coal gasification process 210.
The introduction of oxygen 308 from the electrolyzers 304 into the
entrained flow gasifier 216 eliminates the need for an oxygen
supply from an air separation unit.
[0059] Electrolyzers 304 may include conventional electrolyzers 304
such as electrolyzers used in conventional low temperature
electrolysis, high temperature electrolysis, or thermochemical
processes.
[0060] According to particular embodiments of the invention, coal
211 for use in the coal gasification process 210 may be fed to one
or more dryers 212 to reduce moisture in the coal 211. The one or
more dryers 212 may include heat exchangers or other conventional
drying processes. The dried coal 213 may be fed to a pulverizer 214
where the dried coal 213 is pulverized, crushed, or otherwise
reduced to a sufficient size for coal gasification. The pulverized
coal 215 may be fed to an entrained flow gasifier 216 to gasify the
pulverized coal 215. Oxygen 308 or compressed oxygen 308 from the
electrolysis process 300 is also fed to the entrained flow gasifier
216 to facilitate gasification of coal within the entrained flow
gasifier 216. Steam 50 and boiler feed water 52 may also be fed to
the entrained flow gasifier 216. The gasification of coal within
the entrained flow gasifier 216 produces a synthesis gas product
216a, or syngas, comprising hydrogen and carbon monoxide. Slag 216b
produced in the entrained flow gasifier 216 may be removed from the
entrained flow gasifier 216 and disposed of as desired. Heat
generated in the entrained flow gasifier 216 may be used to produce
medium pressure steam 54 from the boiler feed water 52 introduced
to the entrained flow gasifier 216. The medium pressure steam 54
produced by the entrained flow gasifier 216 may be used elsewhere
in the coal-to-liquid hydrocarbon production process 200 as
desired.
[0061] While the coal gasification processes 210 of the
coal-to-liquid hydrocarbon production processes 200 described in
various embodiments of the invention utilize entrained flow
gasifiers 216 to gasify coal, it is understood that other
gasification units may be substituted for the entrained flow
gasifiers 216. For example, gasification units that may be used
with coal gasification processes 210 of the various embodiments of
the invention may include, but are not limited to, entrained flow
gasifiers, counter-current fixed bed gasifiers, co-current fixed
bed gasifiers, and fluid bed gasifiers. Other coal gasification
equipment capable of producing a synthesis gas from the
gasification of coal could also be used as a gasification unit.
[0062] The entrained flow gasifier 216, or other gasification
equipment, may be configured to gasify coal at a desired
temperature. In certain embodiments, for example, the entrained
flow gasifier 216 may operate within a temperature range of between
about 1300.degree. C. and about 1600.degree. C. Operation within
such a temperature range may reduce the formation of carbon dioxide
(CO.sub.2) and methane (CH.sub.4) within the entrained flow
gasifier 216.
[0063] The synthesis gas product 216a from the coal gasification
process 210 may be fed to a gas and heat recovery process 220 which
produces a synthesis gas product 223 that may be fed to a gas
cleanup process 230. The gas cleanup process 230 removes pollutants
such as hydrogen sulfide (H.sub.2S) and carbon dioxide (CO.sub.2)
from the synthesis gas product 223. For example, processes such as
Rectisol processes, Claus processes, SCOT processes, and TEG
dehydration processes may be used to remove pollutants from the
synthesis gas product 223. The cleaned synthesis gas from the gas
cleanup process 230 may be fed to a Fischer-Tropsch process 260 as
a syngas product stream 247. The Fischer-Tropsch process 260 may
convert the syngas product stream 247 into naphtha products 286 and
diesel products 287. Tail gases 291 from the Fischer-Tropsch
process 260 may be fed to a heat recovery and power generation
process 290 to produce electricity.
[0064] According to other embodiments of the invention, hydrogen
produced by a water-splitting process 300 in a coal-to-liquid
hydrocarbon production process 200 may be added to synthesis gas
produced in the coal-to-liquid hydrocarbon production process 200.
As illustrated in FIG. 3, hydrogen 310 produced by one or more
electrolyzers 304 in a water-splitting process 300 may be
compressed by one or more compressors 314 and combined with a
synthesis gas product stream 247 being fed to a Fischer-Tropsch
process 260 of a coal-to-liquid hydrocarbon production process 200.
The addition of hydrogen 310 to the synthesis gas product stream
247 may be used to obtain a desired ratio of hydrogen to carbon
monoxide within the synthesis gas product stream 247. For example,
in some coal-to-liquid hydrocarbon production processes 200
according to embodiments of the invention, the synthesis gas fed to
the Fischer-Tropsch process 260 may have a hydrogen to carbon
monoxide mole ratio (H.sub.2/CO) of about 2.15. The ability to
supplement the synthesis gas product stream 247 with hydrogen from
the water-splitting process 300 allows the H.sub.2/CO ratio of the
Fischer-Tropsch process 260 feed gas to be tailored or configured
as desired.
[0065] The addition of hydrogen 310 to the synthesis gas product
stream 247 may also reduce or eliminate the need for water-gas
shift chemistry in a gas cleanup process 230, which removes the
need for the inclusion of a sour shift reactor in the
coal-to-liquid hydrocarbon production process 200. Instead of
including equipment within the coal-to-liquid hydrocarbon
production process 200 to shift the ratio of hydrogen to carbon
monoxide in a synthesis gas product stream 247, hydrogen 310
produced in a water-splitting process 300 may be combined with the
synthesis gas product stream 247 to achieve the desired ratios of
hydrogen and carbon dioxide for a Fischer-Tropsch process 260.
[0066] One configuration for particular embodiments of the
invention is illustrated in FIG. 3. A synthesis gas product 216a
from the coal gasification process 210 may be introduced into a
syngas cooler 222 of a gas and heat recovery process 220 of the
coal-to-liquid hydrocarbon production process 200. The syngas
cooler 222 cools the hot synthesis gas product 216a and produces a
cool synthesis gas product 223 which is withdrawn from the syngas
cooler 222 and fed to the gas cleanup process 230. Boiler feed
water 52 fed to the syngas cooler 222 may absorb heat from the hot
synthesis gas product 216a fed to the syngas cooler 222, resulting
in the production of high pressure steam 56 and medium pressure
steam 54 which are removed from the syngas cooler 222 for use
elsewhere in the coal-to-liquid hydrocarbon production process
200.
[0067] The syngas cooler 222 may include conventional equipment for
cooling gases produced in a coal gasification process 210. For
example, the syngas cooler 222 may include one or more convective
syngas coolers, radiant syngas coolers, or a combination of
convective and radiant syngas coolers.
[0068] The synthesis gas product 223 may be fed to a gas cleanup
process 230. The gas cleanup process may include a cyclone 232, a
water scrubber 234, a black water treatment system 236, a heat
exchanger 240, a condenser 242, an activated carbon bed 244, a
Rectisol process 246, a Claus process 248, a SCOT process 250, a
TEG dehydration process 254, and one or more compressors 252, 256
associated with the TEG dehydration process 254. While the gas
cleanup process 230 illustrated in FIG. 3 includes single pieces of
equipment utilized in the process, multiple pieces of equipment may
also be used. For example, the heat exchanger 240 may be replaced
by two or more heat exchangers 240 as desired. Scaling of the gas
cleanup process 230 in order to accommodate desired product flows
is feasible.
[0069] Fly ash 233 and other particulates entrained in the
synthesis gas product 223 fed to the cyclone 232 may be removed
from the cyclone 232 and the synthesis gas product may be fed to a
water scrubber 234. Water 60 fed to the water scrubber 234 removes
pollutants and other impurities from the synthesis gas product 223
and discharges the water 60 and other impurities as waste water
stream 234a which may be fed to a black water treatment system 236
or other treatment system to treat the waste water stream 234a. A
scrubbed synthesis gas product 239 from the water scrubber 234 may
be fed to a heat exchanger 240 to cool the scrubbed synthesis gas
product 239. Boiler feed water 52 fed to the heat exchanger 240 may
absorb heat from the scrubbed synthesis gas 239, producing steam
such as a medium pressure steam 54 that may be used elsewhere in
the coal-to-liquid hydrocarbon production process 200. The cooled,
scrubbed synthesis gas product 241 may be fed to a condenser 242
where water 60 in the cooled, scrubbed synthesis gas product 241 is
recovered. The synthesis gas product 243 exiting the condenser 242
may then be treated to further remove pollutants from the synthesis
gas product 243.
[0070] Mercury in the synthesis gas product 243 may be removed by
contacting the synthesis gas product 243 with activated carbon in
an activated carbon bed 244. The synthesis gas product 243 exiting
the activated carbon bed 244 may be fed to one or more processes
for removing hydrogen sulfide and carbon dioxide from the synthesis
gas product 243. In addition, a portion of the synthesis gas
product 243 may be diverted to a compressor 224 and then mixed with
synthesis gas product 216a from the coal gasification process 210.
In some embodiments, a portion of the synthesis gas product 243
exiting the condenser 242 may be diverted to a compressor 224
rather than being fed to the activated carbon bed 244. This
diversion may be in combination with or in place of the diversion
of the portion of synthesis gas product 243 exiting the activated
carbon bed 244.
[0071] As illustrated in FIG. 3, at least a portion of the
synthesis gas product 243 may be fed to a Rectisol process 246 to
remove hydrogen sulfide (H.sub.2S) and carbon dioxide (CO.sub.2)
from the synthesis gas product 243. The Rectisol process 246 may
produce a first product stream 246a containing hydrogen sulfide and
carbon dioxide, a second product stream 246b containing carbon
dioxide, a purge gas 246c, and a synthesis gas product stream
247.
[0072] The first product stream 246a may be further treated by a
Claus process 248 and a SCOT process 250 to remove sulfur and
carbon dioxide pollutants from the first product stream 246a and to
produce tail gases 250a that are sufficiently clean to be released
into the environment. A sulfur product 248a may be discharged from
the Claus process 248.
[0073] The second product stream 246b may be compressed in
compressor 252 and treated with a TEG dehydration process 254 to
purify carbon dioxide from the second product stream 246b. Carbon
dioxide gas removed from the second product stream 246b may be fed
to a compressor 256 and cooled to form liquid carbon dioxide 257.
The liquid carbon dioxide 257 may be pumped with a pump 258 to a
storage container or other process as desired. Thus, carbon dioxide
pollutants recovered from the synthesis gas product 243 may be
converted to liquid carbon dioxide for use or sale.
[0074] The purge gas 246c from the Rectisol process 246 may be
released into the environment. Rectisol processes 246, Claus
processes 248, SCOT processes 250 and TEG dehydration processes 254
are well known processes and conventional equipment may be readily
utilized to carry out such processes in the gas cleanup process 230
of the coal-to-liquid hydrocarbon production processes 200
according to embodiments of the invention may be readily
utilized.
[0075] The synthesis gas product stream 247 produced by the gas
cleanup process 230 may be fed to one or more Fischer-Tropsch
processes 260 where the synthesis gas product stream 247 is
converted into naphtha products 286 and diesel products 287.
According to embodiments of the invention, hydrogen 310 from a
water-splitting process 300 may be mixed with the synthesis gas
product stream 247 prior to or at the same time that the synthesis
gas product stream 247 is fed to the Fischer-Tropsch process 260.
The addition of hydrogen 310 to the synthesis gas product stream
247 may be controlled to achieve a desired ratio of hydrogen and
carbon monoxide being fed to the Fischer-Tropsch process 260.
[0076] Tail gases 291 from the Fischer-Tropsch process 260 may be
fed to a heat recovery and power generation process 290 if
desired.
[0077] Although the coal-to-liquid hydrocarbon production process
200 illustrated in FIG. 3 includes the use of both the hydrogen 310
and oxygen 308 produced by the water-splitting process 300 in the
coal-to-liquid hydrocarbon production process 200, it is understood
that various embodiments of the invention may also utilize just the
oxygen 308 produced by the electrolyzers 304 as a feed stream to
the coal gasification process 210 as illustrated in FIG. 2, or just
the hydrogen 310 produced by the electrolyzers 304 as a synthesis
gas product stream 247 additive.
[0078] In still other embodiments of the invention, hydrogen 310
produced by a water-splitting process 300 may be fed to a
Fischer-Tropsch process 260 and combined with hydrogen produced by
a hydrogen membrane of the Fischer-Tropsch process 260 (not shown).
For example, hydrogen 310 produced by the water-splitting process
300 may be used with hydrocracking and hydrotreating processes of a
Fischer-Tropsch process 260.
[0079] In other embodiments of the invention, hydrogen 310 produced
by a water-splitting process 300 may be fed to a gasifier 216 as
illustrated in FIG. 3. Hydrogen 310 fed to a gasifier 216 may
assist in the conversion of carbon dioxide to carbon monoxide when
carbon dioxide is formed in the gasifier 216 or recycled to the
gasifier 216.
[0080] The combination of a water-splitting process 300 with a
coal-to-liquid hydrocarbon production process 200 as illustrated in
FIGS. 2 and 3 offers many advantages over conventional
coal-to-liquid hydrocarbon production processes. For example, as
illustrated in FIG. 2, the use of oxygen 308 produced by the
water-splitting process 300 with the coal gasification process 210
may reduce or eliminate the need for an air separation unit to
produce oxygen for coal gasification. In other instances, the
hydrogen 310 produced in the water-splitting process 300 may be
used to control the ratios of hydrogen and carbon monoxide in a
synthesis gas product stream 247 fed to a Fischer-Tropsch process
260. The ability to balance or shift the ratios of hydrogen and
carbon monoxide in the synthesis gas product stream 247 with
hydrogen 310 produced by the water-splitting process 300 reduces or
eliminates the need for sour shift reaction equipment in the
coal-to-liquid hydrocarbon production process 200. The hydrogen 310
may also be utilized to facilitate hydrocracking and hydrotreating
processes within a Fischer-Tropsch process 260. Thus, the use of
oxygen 308, hydrogen 310, or a combination of oxygen 308 and
hydrogen 310 produced by a water-splitting process 300 with a
coal-to-liquid hydrocarbon production process 200 may reduce the
amount of equipment necessary to operate the coal-to-liquid
hydrocarbon production process 200 and reduce costs associated with
the operation of the processes of the coal-to-liquid hydrocarbon
production process 200.
[0081] The combination of a water-splitting process 300 with a
coal-to-liquid hydrocarbon production process 200 as illustrated in
FIGS. 2 and 3 may also improve the production of liquid
hydrocarbons and liquid fuel products and reduce the amount of
pollutants generated in the coal-to-liquid hydrocarbon production
process 200. For example, simulations of the conventional CTL
process 100 illustrated in FIG. 1 were run and compared to
simulations of the coal-to-liquid hydrocarbon production process
200 illustrated in FIG. 3. The simulations were performed using
Aspen.TM. software and the results are illustrated in Table 1:
TABLE-US-00001 TABLE 1 CTL Process 100 CTL Process 200 (FIG. 1)
(FIG. 3) Coal Feed (ton/day) 18,840 18,840 Liquid Fuel Produced
26,037 58,182 (bbl/day) Conversion 1.38 3.09 (bbl liquids/ton of
coal) Carbon Partitioned to 29.5 65.8 Liquid Fuel (% of carbon
input)
[0082] The data of Table 1 indicate that the coal-to-liquid
hydrocarbon production process 200 according to embodiments of the
invention produces more liquid fuel per ton of coal than does a
conventional CTL process 100. The increased production of liquid
fuel from the coal in a coal-to-liquid hydrocarbon production
process 200 also increases the amount of carbon converted to liquid
fuel, which in turn results in less carbon in the process which can
be converted to carbon dioxide pollutants. Thus, the use of oxygen
308 and hydrogen 310 produced by a water-splitting process 300 with
a coal-to-liquid hydrocarbon production process 200 according to
embodiments of the invention provides improved production of liquid
hydrocarbon fuels over conventional carbon-to-liquid hydrocarbon
production processes and reduces carbon-based pollutants produced
in such processes.
[0083] According to still other embodiments of the invention,
carbon recovery in a coal-to-liquid hydrocarbon production process
200 may be improved by recycling carbon-containing gas streams in
the coal-to-liquid hydrocarbon production process 200 to the coal
gasification process 210.
[0084] For example, in certain embodiments of the invention, carbon
dioxide gases separated from the synthesis gas product 243 fed to a
Rectisol process 246 may be recycled to the entrained flow gasifier
216. The introduction of additional carbon dioxide into the
entrained flow gasifier 216 may result in additional reactions of
the carbon dioxide with hydrogen to produce additional carbon
monoxide. An example of such a process is illustrated in FIG.
4.
[0085] The second product stream 246b produced in the Rectisol
process 246 contains carbon dioxide. As illustrated in FIG. 4, the
second product stream 246b may be compressed in compressor 252 and
recycled to the entrained flow gasifier 216, or other gasification
equipment, so that the carbon dioxide in the second product stream
246b may react with hydrogen in the entrained flow gasifier 216 to
produce carbon monoxide.
[0086] The ability to redirect the second product stream 246b from
the Rectisol process 246 in the coal-to-liquid hydrocarbon
production process 200 illustrated in FIG. 4 is achieved in part
because of the integration of the water-splitting process 300 with
the coal-to-liquid hydrocarbon production process 200. The
elimination of a sour shift reactor from the coal-to-liquid
hydrocarbon production process 200 due to the availability of
hydrogen 310 from the water-splitting process 300 reduces the size
of the second product stream 246b from the Rectisol process 246.
The reduction in the size of the second product stream 246b allows
the second product stream 246b to be recycled to the coal
gasification process 210. Recycling of the carbon-containing second
product stream 246b improves carbon conversion in the
coal-to-liquid hydrocarbon production process 200 and decreases the
amount of carbon-based pollutants produced by the process.
[0087] In still other embodiments of the invention, tail gases 291,
light fuel components, or a mixture of tail gases 291 and light
fuel components from a Fischer-Tropsch process 260 of a
coal-to-liquid hydrocarbon production process 200 may be recycled
to the coal gasification process 210. In particular,
carbon-containing tail gases 291 and any light fuel components may
be fed to the entrained flow gasifier 216, or other gasification
unit, to facilitate the conversion of the carbon in the coal to
desirable fuel products. An example of such recycling is
illustrated in FIG. 5.
[0088] As illustrated in FIG. 5, the tail gases 291 from a
Fischer-Tropsch process 260 are recycled to the entrained flow
gasifier 216. The tail gases 291 may undergo compression in
compressor 299 before being fed to the entrained flow gasifier 216.
The recycling of the tail gases 291 to the coal gasification
process 210 eliminates the tail gas 291 feed for a heat recovery
and power generation process 290 in the coal-to-liquid hydrocarbon
production process 200. The elimination of the tail gas 291 feed to
a heat recovery and power generation process 290 eliminates the
need for the heat recovery and generation equipment associated with
such processes. In addition, recycling of carbon-containing tail
gases 291, and in some instances light hydrocarbons, from the
Fischer-Tropsch process 260 to the coal gasification process 210
facilitates further conversion of the tail gases 291 into synthesis
gas. For example, the tail gases 291 may include light
hydrocarbons, residual hydrogen, carbon monoxide, water, and carbon
dioxide that may be converted into synthesis gas in the coal
gasification process 210.
[0089] While the process illustrated in FIG. 5 includes the
recycling of the tail gases 291 from the Fischer-Tropsch process
260 and the second product stream 246b from the Rectisol process
246 to the entrained flow gasifier 216, it is understood that the
tail gases 291 from the Fischer-Tropsch process 260 may be recycled
without recycling the second product stream 246b to the entrained
flow gasifier 216. In addition, it is understood that the recycled
tail gases 291 from the Fischer-Tropsch process 260 may include all
or only a portion of the total tail gases 291 produced by the
Fischer-Tropsch process 260. Similarly, the second product stream
246b from the Rectisol process 246 that is recycled to the
entrained flow gasifier 216 may include all or only a portion of
the second product stream 246b.
[0090] It is also understood that the recycling of the second
product stream 246b, the tail gases 291, or a portion or all of the
second product stream 246b and tail gases 291 to the entrained flow
gasifier 216 may occur in a process that does not employ a
water-splitting process 300. For example, in process 100 of FIG. 1,
carbon-containing products from the gas cleanup process 130 and
from the Fischer-Tropsch process 160 may be recycled to the
entrained flow gasifier 116 in a manner similar to that illustrated
in FIGS. 4 and 5.
[0091] In some embodiments, the steam generated within the
coal-to-liquid hydrocarbon production process 200 may be recovered
and combined with heat from one or more nuclear power sources 302
associated with the water-splitting process 300 to superheat the
recovered steam and generate electricity according to conventional
methods. In still other embodiments of the invention, steam
recovered from the coal-to-liquid hydrocarbon production process
200 may be utilized or superheated by one or more nuclear power
sources 302 or reactors in a water-splitting process 300 associated
with the coal-to-liquid hydrocarbon production process 200.
[0092] A simulated comparison of the coal-to-liquid hydrocarbon
production process 200 illustrated in FIG. 5 with the
coal-to-liquid hydrocarbon production process 200 illustrated in
FIG. 3 and with the conventional CTL process 100 illustrated in
FIG. 1 was performed using Aspen.TM. software. In addition, a
smaller coal-to-liquid hydrocarbon production process 200 based
upon the configuration illustrated in FIG. 5 was simulated to
compare with larger process configurations. The results of the
simulations are given in Table 2:
TABLE-US-00002 TABLE 2 CTL CTL CTL Process Process Process 100 200
200 Small CTL (FIG. 1) (FIG. 3) (FIG. 5) Process Coal Feed 18,800
18,800 18,800 5,800 (ton/day) Liquid Fuel 26,000 58,200 84,672
26,000 Produced (bbl/day) Conversion 1.38 3.09 4.49 4.49 (bbl
liquids/ton coal) Yield of Liquid Fuel 29.5 65.8 95.7 95.7 (% of
carbon input)
[0093] The data in Table 2 confirm that the coal-to-liquid
hydrocarbon production processes 200 illustrated in FIGS. 3 and 5
produce a greater amount of liquid hydrocarbon fuels for a given
amount of coal than does the conventional CTL process 100
illustrated in FIG. 1. In addition, the coal-to-liquid hydrocarbon
production process 200 illustrated in FIG. 5 produces a greater
amount of liquid hydrocarbon fuel as compared to the coal-to-liquid
hydrocarbon production process 200 illustrated in FIG. 3 for an
equivalent amount of coal. The data also indicate that the yield of
liquid hydrocarbon fuels produced as a percentage of carbon input
into the processes is greatest in the coal-to-liquid hydrocarbon
production process 200 illustrated in FIG. 5. The coal-to-liquid
hydrocarbon production process 200 illustrated in FIG. 3 is also
better at converting carbon to liquid hydrocarbon fuels than is the
conventional CTL process 100 illustrated in FIG. 1.
[0094] The data of Table 2 also provide some insight into the
production efficiencies of certain embodiments of the invention.
The small coal-to-liquid hydrocarbon production process simulated
for Table 2 produces the same amount of liquid hydrocarbon fuels as
does the conventional CTL process illustrated in FIG. 1. However,
the small coal-to-liquid hydrocarbon production process based upon
the configuration of the coal-to-liquid hydrocarbon production
process 200 illustrated in FIG. 5 produces the same amount of
liquid hydrocarbon fuels as does the conventional CTL process 100
with 5,800 tons of coal per day as compared to the 18,800 tons per
day required for the conventional CTL process 100. As a result,
coal-to-liquid hydrocarbon production processes 200 according to
embodiments of the invention are much more efficient at converting
coal to hydrocarbon fuels than are conventional processes.
[0095] The data in Table 2 also illustrate the fact that
coal-to-liquid hydrocarbon production processes according to
particular embodiments of the invention have reduced pollutant
emissions as compared to conventional CTL processes 100. The
increased yield of liquid fuel based upon the carbon input into
each process indicates that the processes illustrated in FIGS. 3
and 5 convert more carbon to liquid fuel than does a conventional
process, resulting in less carbon-based pollution from the
coal-to-liquid hydrocarbon production process.
[0096] According to various other embodiments of the invention, the
second product stream 246b from the Rectisol process 246 may be
combined and mixed with the tail gases 291 from the Fischer-Tropsch
process 260 as illustrated in FIG. 6. The second product stream
246b contains carbon dioxide, which may react with the fuel
components in the tail gases 291 in a reactor 400. A catalyst may
be present in the reactor 400 during the reaction. For example, the
tail gases 291 from the Fischer-Tropsch process 260 may include
hydrocarbons or other liquid fuels, represented by the chemical
formula (--CH.sub.2--). The mixing of the carbon dioxide in the
second product stream 246b with the hydrocarbons or fuels in the
tail gases 291 may result in a reaction which produces carbon
monoxide and hydrogen as shown in Reaction 2:
CO.sub.2+(--CH.sub.2--).fwdarw.2CO+H.sub.2 (2).
Thus, the carbon dioxide pollutants in the second product stream
246b may react with the tail gases 291 from the Fischer-Tropsch
process 260 to produce additional carbon monoxide and hydrogen, or
syngas, that may be used to produce liquid fuels or liquid
hydrocarbons according to embodiments of the invention. In
addition, the second product stream 246b and the tail gases 291 are
clean gas streams that have been previously treated to remove
unwanted pollutants. Therefore, the reaction to produce carbon
monoxide and hydrogen according to Reaction 2 produces a clean
product of carbon monoxide and hydrogen that does not need to be
treated to remove pollutants.
[0097] As illustrated in FIG. 6, in some embodiments of the
invention a product 410 containing carbon monoxide and hydrogen
formed in the reactor 400 may be recycled and combined with the
synthesis gas product 243 fed to the Rectisol process 246. The
addition of the product 410 to the synthesis gas product 243 adds
additional carbon monoxide and hydrogen to the synthesis gas
product 243, which may be converted to liquid hydrocarbons or other
carbon-containing liquid fuels in the Fischer-Tropsch process 260
or other liquid fuel production process.
[0098] In other embodiments of the invention, the product 410
containing carbon monoxide and hydrogen formed in the reactor 400
may be recycled and combined with the synthesis gas product stream
247 from the Rectisol process 246. The combination of the product
410 and the synthesis gas product stream 247 may be fed to a
Fischer-Tropsch process 260, or other liquid fuel production
process, to produce liquid hydrocarbons or other carbon-containing
liquid fuels.
[0099] While the product 410 may be recycled and included in the
synthesis gas product 243 or in the synthesis gas product stream
247, in some embodiments, product 410 may be recycled to both the
synthesis gas product 243 and to the synthesis gas product stream
247. The amount of carbon monoxide and hydrogen in product 410 may
also be controlled such that the carbon monoxide and hydrogen
ratios resulting from the combination of the product 410 with the
synthesis gas product 243, with the synthesis gas product stream
247, or with both the synthesis gas product 243 and synthesis gas
product stream 247 are at a desired ratio.
[0100] The recapture of the waste carbon dioxide separated by the
Rectisol process 246 in the liquid fuel production process may
improve the total amount of carbon conversion achieved by the
coal-to-liquid hydrocarbon production process 200. The conversion
of greater amounts of carbon to liquid fuels also decreases the
amount of coal or other carbon-containing resource necessary to
produce the liquid fuels. In addition, the ability to recapture
carbon dioxide produced by the coal-to-liquid hydrocarbon
production process 200 and to convert it into carbon-containing
liquid fuels decreases the overall amount of carbon dioxide
pollution produced by the coal-to-liquid hydrocarbon production
process 200.
[0101] According to other embodiments of the invention, steam 425
may also be mixed with the second product stream 246b from the
Rectisol process 246 and with tail gases 291 from a Fischer-Tropsch
process 260 or other liquid fuel production process. For example,
as illustrated in FIG. 7, steam 425 may be fed to the reactor 400
along with the second product stream 246b and the tail gases 291.
In some embodiments of the invention, steam 425 may be added
directly to the reactor 400. In other embodiments, steam 425 may be
added to the second product stream 246b, to the tail gases 291, or
to both the second product stream 246b and to the tail gases 291
prior to introduction into the reactor 400. In still other
embodiments, steam 425 may be added to the second product stream
246b and to the tail gases 291 before being introduced into the
reactor 400 along with steam 425 introduced directly into the
reactor 400. The combination of the second product stream 246b with
steam 425 or the tail gases 291 with steam 425 may be performed in
any desired manner.
[0102] The combination of steam 425 with the second product stream
246b and the tail gases 291 produces water-gas shift reaction and
steam reformation of the second product stream 246b and the tail
gases 291. The steam reformation and water-gas shift in the second
product stream 246b and tail gases 291 improve the yield of carbon
monoxide and hydrogen from the reaction of the carbon dioxide of
the second product stream 246b with the tail gases 291 and the
added steam 425. The improved yield improves the overall
performance of the process and the overall conversion of carbon to
liquid fuels.
[0103] The use of steam 425 to improve the reaction of carbon
dioxide and tail gases 291 to produce carbon monoxide and hydrogen
may also produce a desired ratio of carbon monoxide to hydrogen for
liquid fuels production. For example, the amount of steam 425 added
to the second product stream 246b, to the tail gases 291, or to the
reactor 400, may be tailored to achieve a desired carbon monoxide
to hydrogen ratio sufficient for direct feed to a Fischer-Tropsch
process 260 or other liquid fuel production process. In some
instances, the addition of steam 425 may be controlled to produce a
ratio of hydrogen to carbon monoxide in 2.1 to 1.0 molar ratio,
which may be optimal for production of liquid fuels in a
Fischer-Tropsch process 260. In addition, steam 425 may be added to
the second product stream 246b, to the tail gases 291, or to the
reactor 400 for syngas production. The amount of steam 425 added
may produce a syngas with a H.sub.2:CO ratio that, when added to
the synthesis gas product stream 247, makes a combined stream with
the desired ratio of hydrogen to carbon monoxide.
[0104] A simulation of the effect of water (steam 425) was
determined using Aspen.TM. software. Equilibrium calculations were
conducted for the addition of steam 425 to the second product
stream 246b and the tail gases 291. For comparison, equilibrium
calculations were also conducted for the reaction of the second
product stream 246b and the tail gases 291. The results of the
simulations are given in Table 3:
TABLE-US-00003 TABLE 3 Tailgas + CO.sub.2 + H.sub.2O (Steam
Reforming) Tailgas + Steam-to-Dry Gas CO.sub.2 (Dry Reforming)
Ratio = 1.0 T = 1500.degree. F. T = 2000.degree. F. T =
1500.degree. F. T = 2000.degree. F. Inputs: Tailgas, 7,376 7,376
7,376 7,376 lbmol/hr CO.sub.2, lbmol/hr 977 977 977 977 H.sub.2O,
lbmol/hr -- -- 8,339 8,339 Outputs: H.sub.2, lbmol/hr 4,026 9,398
8,150 17,600 CO, lbmol/hr 670 2,227 570 8,426 Soot, lbmol/hr 5,406
6,179 6,991 186 H.sub.2/CO Ratio 6.00 4.22 14.30 2.09
[0105] The equilibrium calculations in Table 3 show that reforming
at an elevated temperature produces a significant quantity of CO
and H.sub.2. The reaction simulation assumed that the output
reached thermodynamic equilibrium at 420 psig, which is similar to
the pressures of the two feed streams and the pressure of the
Fischer-Tropsch system to which these products are delivered. In
addition to the CO and H.sub.2, the reactor effluent contained
steam, CO.sub.2, CH.sub.4, and small amounts of ethane and propane.
Table 3 also shows the strong effect on the reactor product
distribution of increasing the temperature from 1500.degree. F. to
2000.degree. F. Controlling the temperature, along with controlling
the relative amount of each feed stream, is one method of
controlling the products of the reaction. The presence of the water
(steam 425) also produced greater amounts of CO and H.sub.2. In
addition, the water drastically reduced soot formation and achieved
H.sub.2/CO ratios around 2, which are optimal for Fischer-Tropsch
synthesis.
[0106] According to other embodiments of the invention, steam 425
may be supplied from a renewable energy source. For example, steam
425 produced by a nuclear power plant or by the heat produced by a
nuclear reaction, may be combined with the second product stream
246b or tail gases 291 according to embodiments of the invention.
In other instances, steam 425 may be produced by other renewable
energy sources, such as by wind power, geothermal power, tidal
power, and solar power. The use of a renewable or alternative
energy source to produce the steam 425 may make up for any heat
loss resulting from the recycling of the tail gases 291 rather than
the burning of the tail gases 291 as performed in conventional
processes, such as that illustrated in FIG. 1. The use of nuclear
power to provide the steam 425 requirements of embodiments of the
invention may be advantageous especially if the steam 425 is being
used with a coal-to-liquid hydrocarbon production process 200
already employing the use of nuclear power.
[0107] In certain other embodiments of the invention, hydrogen or
oxygen produced by a water-splitting process 300 may be added to
the reactor 400 or product 410 produced by the reaction of the
second product stream 246b with the tail gases 291 to alter the
composition of the product 410 being recycled to the liquid fuel
production process.
[0108] In still other embodiments of the invention, a portion of
the second product stream 246b may be fed to the coal gasification
process 210, such as to an entrained flow gasifier 216, and the
remainder recycled to form product 410. Similarly, a portion of the
tail gases 291 may also be fed to the coal gasification process 210
and the remaining portion recycled to form product 410 or fed to a
combustion process. For example, as illustrated in FIG. 8, a
portion of the second product stream 246b is fed to reactor 400
while a second portion is fed to the coal gasification process 210.
Likewise, a portion of the tail gases 291 are fed to the reactor
400 and a second portion of the tail gases 291 are fed to the coal
gasification process 210.
[0109] While various embodiments of the invention have been
described with respect to a coal-to-liquid hydrocarbon production
process 200, the embodiments of the invention may be used with
other carbon-conversion processes where carbon-containing products
are converted into carbon-containing liquid fuels such as liquid
hydrocarbons, methanol, dimethyl ether, and other liquid fuels. For
example, the product 410 produced in those embodiments illustrated
in FIGS. 6 through 8 may be used as a syngas feed to a liquid fuels
production process or may be combined with a carbon-containing gas
feed stream for conversion in a liquid fuels production
process.
[0110] While various embodiments of the invention employ the use of
a Fischer-Tropsch process 260 to produce liquid hydrocarbons from a
synthesis gas, it is understood that other processes may be used in
combination with, or as a substitute for, the Fischer-Tropsch
process 260 to produce liquid hydrocarbons, liquid fuel products,
or a combination of liquid hydrocarbons and liquid fuel products.
For example, any processes capable of converting a synthesis gas to
liquid hydrocarbons or liquid fuel products may be used in place
of, or in combination with, the Fischer-Tropsch process 260. In
particular, processes having preferred hydrogen to carbon monoxide
ratios may be combined with various embodiments of the invention to
produce liquid hydrocarbons and liquid fuel products according to
the desired ratios. In addition, synthesis gas conversion processes
which produce carbon-containing purge gases may be integrated with
various embodiments of the invention to recycle the purge gases to
produce additional synthesis gas for conversion to liquid
hydrocarbons and liquid fuel products. Examples of processes that
may be substituted for, or combined with, a Fischer-Tropsch process
260 include, but are not limited to, processes for producing
methanol or dimethyl ether.
[0111] In addition, while various embodiments of the invention are
described with respect to the production of liquid hydrocarbons, it
is understood that other liquid fuel products may also be produced
using such embodiments.
[0112] The integration of a water-splitting process 300 with a
coal-to-liquid hydrocarbon production process 200 according to
embodiments of the invention improves the conversion of carbon in
coal to liquid hydrocarbon fuels while also reducing the total
amount of carbon pollutants produced in such processes.
[0113] While the water-splitting processes 300 of the present
invention include the use of nuclear power sources 302 to provide
heat or electricity for the water-splitting process 300, other
power supplies may also be used to operate the electrolyzers 304.
For example, nuclear power sources 302 may be substituted or
combined with wind power, hydroelectric power, geothermal power,
tidal power, or solar power to produce sufficient energy to operate
the water-splitting process 300. In addition, conventional
coal-fired or combustion power plants may be used to supply power
to the electrolyzers 304 to generate hydrogen and oxygen for use
with coal-to-liquid hydrocarbon production processes 200 according
to embodiments of the invention.
[0114] The various coal-to-liquid hydrocarbon production processes
200 according to embodiments of the invention may also be scaled up
or scaled down to achieve a desired coal consumption rate or
hydrocarbon production rate. In addition, alternative fuels, such
as carbon-containing fuels, may be used or burned in the
coal-to-liquid hydrocarbon production processes 200 to produce
synthesis gases. For example, fuels that may be used include, but
are not limited to, coal, oil shale, biomass, refuse, waste
materials, natural gas, lignite, and mixtures thereof.
[0115] Having thus described certain embodiments of the present
invention, it is understood that the invention defined by the
appended claims is not to be limited by particular details set
forth in the above description, as many apparent variations thereof
are contemplated without departing from the spirit or scope thereof
as hereinafter claimed.
* * * * *