U.S. patent application number 15/056271 was filed with the patent office on 2016-06-23 for generating power using an ion transport membrane.
The applicant listed for this patent is GTLpetrol, LLC. Invention is credited to Rodney J. Allam.
Application Number | 20160177821 15/056271 |
Document ID | / |
Family ID | 45938954 |
Filed Date | 2016-06-23 |
United States Patent
Application |
20160177821 |
Kind Code |
A1 |
Allam; Rodney J. |
June 23, 2016 |
Generating Power Using an Ion Transport Membrane
Abstract
In some implementations, a system may include a compressor, a
heat exchanger and an ITM. The compressor is configured to receive
an air stream and compress the air stream to generate a pressurized
stream. The heat exchanger is configured to receive the pressured
stream and indirectly heat the pressurized stream using heat from
an oxygen stream from an Ion Transport Membrane (ITM). The ITM is
configured to receive the heated pressurized stream and generate an
oxygen stream and the non-permeate stream, wherein the non-permeate
stream is passed to a gas turbine burner and the oxygen stream is
passed to the heat exchanger.
Inventors: |
Allam; Rodney J.;
(Chippenham, GB) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
GTLpetrol, LLC |
New York |
NY |
US |
|
|
Family ID: |
45938954 |
Appl. No.: |
15/056271 |
Filed: |
February 29, 2016 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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13907528 |
May 31, 2013 |
9273607 |
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15056271 |
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13271994 |
Oct 12, 2011 |
8459039 |
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13907528 |
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61392413 |
Oct 12, 2010 |
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Current U.S.
Class: |
60/783 ;
60/784 |
Current CPC
Class: |
F05D 2220/722 20130101;
Y02E 20/16 20130101; F02C 7/141 20130101; F02C 6/18 20130101; F02C
3/20 20130101; F02C 7/22 20130101; Y02E 20/18 20130101; F05D
2240/35 20130101; Y02E 50/12 20130101; F02C 6/06 20130101; F02C
3/28 20130101; F02C 3/30 20130101; Y02E 50/10 20130101; F05D
2240/24 20130101; Y02E 50/11 20130101; F05D 2220/75 20130101; F05D
2220/32 20130101; F01K 23/10 20130101 |
International
Class: |
F02C 3/20 20060101
F02C003/20; F02C 7/22 20060101 F02C007/22; F02C 6/18 20060101
F02C006/18; F02C 7/141 20060101 F02C007/141 |
Claims
1. A system, comprising: a gas turbine including a turbine
compressor and an expander, wherein the turbine compressor
discharges an air stream in connection with compressing air used
during combustion; a separate compressor configured to receive the
air stream and compress the air stream to generate a pressurized
stream; a first heat exchanger configured to receive all or at
least a portion of the pressured stream and indirectly heat the
pressurized stream using heat from an oxygen stream from an Ion
Transport Membrane (ITM); a second heat exchanger configured to
receive at least a portion of the heated pressurized air or the
total pressurized air stream from the first heat exchanger and
indirectly heat the pressurized stream to the ITM inlet temperature
using heat from the non-permeate stream from the ITM which has been
further heated; the ITM configured to receive the heated
pressurized stream and generate an oxygen stream and the
non-permeate stream, wherein the non-permeate stream is passed to a
fuel gas burner and the oxygen stream is passed to the first heat
exchanger; a fuel gas burner configured to receive the non-permeate
stream and combust a fuel gas in combination with the non-permeate
stream to generate a heated non-permeate stream, a second heat
exchanger configured to receive the heated non-permeate stream from
the gas turbine burner and heat at least a portion of the
pressurized stream using heat from the heated non-permeate stream,
wherein the heated non-permeate stream is cooled during the
indirect heating; a conduit configured to receive the cooled
non-permeate stream from the second heat exchanger and introduce
the cooled non-permeate in at least one of a fuel gas for the gas
turbine or at a point between the compressor and the expander; and
a gas turbine fuel gas burner which combusts a fuel gas mixed with
at least a portion of the none permeate stream in air from the gas
turbine compressor section. wherein a temperature of the
combination of the fuel gas and the non-permeate stream is below a
predefined threshold temperature for the gas turbine burner, and a
concentration of oxygen in the heated non-permeate stream is such
that when mixed with a fuel gas stream results in an oxygen
concentration below a lower flammable limit of the mixture.
2. A system as defined in claim 1, wherein between 30% and 70% of
the heated pressurized stream is received from an air compressor
which is separate from the gas turbine.
3. The system of claim 1, wherein the heated non-permeate stream is
about 700.degree. C. or higher.
4. The system of claim 1, wherein an oxygen concentration of the
heated non-permeate stream is about below 2.5% or less molar
concentration.
5. The system of claim 1, wherein the heated pressurized stream is
a range from about 800.degree. C. to about 900.degree. C.
6. The system of claim 1, wherein the air stream discharged from
the gas turbine compressor as part of the air feed for the ITM is
compressed in a range from about 12 bars to 45 bars.
7. A method, comprising: discharging, from a turbine compressor, an
air stream in connection with compressing air used during
combustion in a gas turbine; compressing the air stream to generate
a pressurized stream; indirectly heating the pressurized stream
using heat from an oxygen stream from an Ion Transport Membrane
(ITM) in a first heat exchanger; generating an oxygen stream and
the non-permeate stream using the ITM, wherein the non-permeate
stream is passed to a fuel gas burner and the oxygen stream is
passed to the first heat exchanger; receiving at least a portion of
the heated pressurized air or the total pressurized air stream from
the first heat exchanger and indirectly heating the pressurized
stream to the ITM inlet temperature using heat from the
non-permeate stream from the ITM which has been further heated
combusting a fuel gas in combination with the non-permeate stream
and air from the gas turbine air compressor section to generate a
heated non-permeate stream, wherein a temperature of the
combination of the fuel gas and the non-permeate stream is below a
predefined threshold temperature for the gas turbine burner inlet
system, and a concentration of oxygen in the heated non-permeate
stream is such that when mixed with a fuel gas stream results in an
oxygen concentration below a lower flammable limit of the mixture;
heating at least a portion of the pressurized stream using heat
from the heated non-permeate stream, wherein the heated
non-permeate stream is cooled during the indirect heating; and
introducing the cooled non-permeate in at least one of a fuel gas
for the gas turbine or at a point between the compressor and the
expander.
8. A method as defined in claim 7, wherein between 30% and 70% of
the heated pressurized stream is received from an air compressor
which is separate from the gas turbine.
9. The method of claim 7, wherein the heated non-permeate stream is
about 700.degree. C. or higher.
10. The method of claim 7, wherein an oxygen concentration of the
heated non-permeate stream is about below 2.5% or less molar
concentration.
11. The method of claim 7, wherein the heated pressurized stream is
a range from about 800.degree. C. to about 900.degree. C.
12. The method of claim 7, wherein the heated pressurized stream is
at a pressure in a range from about 12 bars to 45 bars.
Description
PRIORITY CLAIM OF PRIORITY
[0001] This application is a continuation of and claims the benefit
of priority to U.S. patent application Ser. No. 13/907,528, filed
on May 31, 2013, which is a continuation of Ser. No. 13/271,994,
filed on Oct. 12, 2011, which claims the benefit of priority to
U.S. Provisional Patent Application Ser. No. 61/392,413, filed on
Oct. 12, 2010, the entire contents of which are hereby incorporated
by reference.
TECHNICAL FIELD
[0002] This invention relates to the simultaneous production of
power and pure oxygen and, more particularly, to integrating an
oxygen ion transport membrane with a gas turbine.
BACKGROUND
[0003] Hydrocarbon and carbonaceous feedstock can be converted into
H.sub.2 and CO synthesis gas mixtures with varying ratios of
H.sub.2 to CO. Feedstock may include coals, natural gas, oil
fractions, bitumen and tar-like refinery wastes, pet-coke and
various forms of biomass. The synthesis gas mixtures can be
converted into valuable hydrocarbons and chemicals using catalytic
processes. The synthesis gas can also be converted to H.sub.2 by
reaction of the CO component with steam over a catalyst followed by
CO.sub.2 removal to produce a fuel gas which can be burned in a gas
turbine combined cycle power production system resulting in power
production with CO.sub.2 capture. The conversion of synthesis gas
to valuable hydrocarbon and chemical products generally requires a
large additional amount of power to be provided to the process and
this can be produced from a gas turbine system. The conversion of
these fuels to synthesis generally requires large volumes of oxygen
which is typically used in a partial oxidation of the feedstock.
This oxygen can be produced in a high temperature oxygen ion
transport membrane system which separates oxygen from a high
pressure high temperature air stream by diffusion from a region of
high oxygen partial pressure to low oxygen partial pressure. The
source of the high pressure high temperature air stream can be the
compressed air stream produced in a gas turbine. It is the
objective of this invention to disclose a method of integrating an
oxygen ion transport membrane with a gas turbine using a hydrogen
rich carbon depleted fuel gas to produce simultaneously power and
pure oxygen with high efficiency. It is apparent that the
integration of ITM O2 production modules with existing unmodified
gas turbines requires an external air compressor supplying part or
all of the air flow required for O2 production.
[0004] It is the objective of this invention to propose a system
which will allow all the fuel gas combustion heat used for air
preheating to be recovered at the gas turbine combustion heat input
level so that recovered heat can produce electrical power at 55% to
60% net efficiency.
[0005] It is a further objective of this invention that the fuel
gas is effectively diluted with a nitrogen rich diluent and
supplied at a temperature below 500.degree. C. without loss of
efficiency caused by transferring heat to the steam system.
[0006] It is a further objective of this invention to ensure that
the oxygen content of the diluent stream is reduced to a
concentration at the ITM exit which will never give any safety
hazard when diluent and H.sub.2 or (H.sub.2+CO) fuel gas at
elevated temperature are mixed.
[0007] It is a further objective of this invention that the mixture
of H.sub.2 or (H.sub.2+CO) fuel gas and diluent is within the
necessary LHV value for satisfactory combustion in a gas turbine.
The range would be for LHV values to be greater than about 120
Btu/scf and that the diluted fuel gas mixture would be at the
maximum temperature allowed by the gas turbine vendor.
[0008] Previous methods for optimizing the integration of a gas
turbine and an Ion Transport Membrane which diffuses pure oxygen
from a pressurized heated feed air stream have been described in
references 1, and 2 which all have disadvantages compared to the
present invention as described below.
SUMMARY
[0009] In some implementations, a system can include an Ion
Transport Membrane (ITM) module which separates pure oxygen from
pressurized heated air integrated with a gas turbine to produce
oxygen. An important use for the system is Integrated Gasification
Combined Cycle (IGCC) systems with or without CO.sub.2 capture to
maximize or otherwise increase system efficiency. These
implementations may enable diluent gas with less than 1% O.sub.2 to
be mixed safely with H.sub.2 and/or (H.sub.2+CO) fuel gas. In
addition, the combination of the ITM and the gas turbine minimize
or otherwise reduce heat energy released in the ITM system that is
transferred to the steam system. The air feed to the ITM module may
be heated indirectly so that the partial pressure of O.sub.2 in the
air is not degraded by direct combustion in the feed air stream.
This maximizes or otherwise increases O.sub.2 recovery and
minimizes or otherwise reduces air flow for a fixed O.sub.2
production and membrane area. Also, some implementations may avoid
or otherwise substantially reduce possible contamination of the ITM
membrane from the combustion products.
[0010] The details of one or more embodiments of the invention are
set forth in the accompanying drawings and the description below.
Other features, objects, and advantages of the invention will be
apparent from the description and drawings, and from the
claims.
DESCRIPTION OF DRAWINGS
[0011] FIG. 1 shows the flow scheme for the process in which all
the air flow to the ITM module is taken from the discharge of the
gas turbine compressor; and
[0012] FIG. 2 shows the flow scheme for the process in which there
is an external air compressor which together with air flow taken
from the discharge of the gas turbine air compressor provides all
the air feed to the ITM module.
[0013] Like reference symbols in the various drawings indicate like
elements.
DETAILED DESCRIPTION
[0014] In some implementations, a system may include power
generation from a gas turbine in which a carbonaceous or
hydro-carbonaceous fuel is gasified using a partial oxidation
reaction with pure O.sub.2 generated from an ITM unit. Current
systems, using coal or petroleum coke or residual bitumen as fuel,
typically employ an O.sub.2 fired partial oxidation process to
convert the carbonaceous fuel to a fuel gas comprising H.sub.2+CO
together with feed derived impurities such as H.sub.2S and others.
This fuel gas stream is cooled and impurities such as H.sub.2S and
others are removed. The purified fuel gas is then mixed with
nitrogen and optionally steam before being used as fuel in a gas
turbine combined cycle power generation system. O.sub.2 used for
partial oxidation has traditionally been generated by separating
air in a cryogenic air separation unit to produce substantially
pure O.sub.2. The described implementations uses an O.sub.2 ion
transport membrane (ITM) comprising mixed metal oxides typically in
a perovskite crystal structure with vacancies in the O.sub.2 ion
sites. These structures allow the O.sub.2 ions to become mobile in
the crystal at high temperatures and the diffusion of O.sub.2
across the membrane becomes possible when there is a difference in
activity coefficient across the ITM. The ITM membrane then operates
as a short circuited electrochemical cell. In order to operate the
ITM unit it is necessary to provide a feed air stream at typically
800.degree. C. to 900.degree. C. with a partial pressure of oxygen
of 3 to 4 bar in order to achieve O.sub.2 separation factors of 70%
or more from the feed air in the ITM system and produce sufficient
O.sub.2 to supply the partial oxidation gasifier. The pure O.sub.2
may diffuse through the ITM membrane and may be available at a
pressure typically in the range 0.3 to 0.8 bar. The adiabatically
compressed air leaving the gas turbine air compressor may be heated
to a temperature in the range 800.degree. C. to 900.degree. C. by
direct combustion of a fuel in a first combustor. The heated air
then passes through an ITM membrane module where some of the
O.sub.2 in the air is separated. The outlet O.sub.2 depleted stream
still has sufficient O.sub.2 for combustion of more fuel in the
second gas turbine combustor which raises the temperature to the
design value for entry into the gas turbine expander.
[0015] Gas turbines are very expensive to modify and current high
output, high efficiency gas turbines, which are commercially
available have limited capability to extract a significant
proportion of air leaving the air compressor section for external
use in an ITM system. In some implementations, the ITM air flow may
be taken not only from the gas turbine compressor discharge up to
the maximum flow available but also from a separate air compressor
with external heating of the compressed air feed to the ITM unit.
When burning H.sub.2+CO fuel gas, the fuel gas may be diluted
primarily with a nitrogen rich gas produced as a by-product of air
separation together optionally with steam. This dilution may reduce
the flame temperature and thus reduces NOX formation in the
combustion. It may also load the turbine to maximize power output.
The O.sub.2 depleted non-permeate stream leaving the ITM unit may
have excess N.sub.2 and may be effective as a diluent for the
H.sub.2 or H.sub.2+CO fuel gas flow to the gas turbine burner. A
typical system may have a fuel gas entering the gas turbine burner
at a pressure in excess of the gas turbine air compressor discharge
pressure and a composition of approximately 50% inert diluent and
50% (H.sub.2+CO) or H.sub.2 on a molar basis. The maximum fuel gas
temperature may be limited by the design of the gas turbine fuel
handling system and is generally below 450.degree. C. The diluent
stream which is the ITM non-permeate leaves the ITM module at
850.degree. C. This stream may be derived from an external air
compressor. In general, the combined fuel gas and diluent stream
may be at a temperature below about 450.degree. C.
[0016] In some implementations, the diluent stream may be cooled to
produce high pressure steam for the Rankine steam cycle which may
be part of the combined cycle. The air feed stream to the ITM is
heated to typically 850.degree. C. by one of two methods:
[0017] (a) The direct combustion of fuel gas in the auxiliary air
stream. This process may produce sufficient heat to raise the
temperature of the air stream plus combustion products to
850.degree. C. To illustrate this method, the following cases may
be executed: [0018] (i) The air compressor may be isothermal with a
discharge condition of 22 bars 75.degree. C. and provide all or
substantially all of the air feed to the ITM unit with no air feed
flow from the gas turbine. In this case, about 25% of the oxygen in
the air may be consumed in direct fuel combustion, and the air flow
may have to be increased by about 33% to compensate; and [0019]
(ii) The air compressor may be adiabatic with a discharge
temperature of 486.degree. C. and can mix with a variable quantity
of similar temperature air taken from the gas turbine. About 14% of
the O.sub.2 may be consumed for fuel combustion with an increased
air flow of about 16%. In addition, the compressor power for the
adiabatic machine may be 35% higher than the isothermal
machine.
[0020] The second case (ii) may have a net 18% more power for
compression than case (i) but has 45% less heat generated. Based on
1 lb mol air the extra power 0.224 kW hrs/lb mol air compressed,
while the saving in heat for case (ii) is 1.27 kW. In general, it
may be more efficient to use on an adiabatic air compressor for the
external compressor.
[0021] (b) It has been proposed that the ITM feed air can be heated
from 520.degree. C. to 850.degree. C. in the heat recovery steam
generator (HRSG) associated with the gas turbine which would
require combustion of more fuel in the gas turbine exhaust to raise
its temperature from the range 500.degree. C.-600.degree. C. to the
range 900.degree. C.-1000.degree. C. to provide the necessary
temperature driving force for heat transfer to the ITM feed air
stream. The effect of using fuel gas for direct heating as in case
a(ii) compared to indirect heating in the HRSG is to reduce the air
flow by 14% saving about 0.174 kW/hrs/lb mol ITM feed air.
[0022] The method of indirect heating in the heat recovery steam
generator or HRSG may reduce the amount of compressed air flow (no
combustion air may be used) but the whole gas turbine discharge
flow may be heated from about 600.degree. C. to about 875.degree.
C. For a typical integrated gasification combined cycle (IGCC)
system, the ITM air flow may be about 25% of the gas turbine air
flow when direct combustion heating is used and the ITM module may
be designed for 80% O.sub.2 recovery. The heat transferred to the
ITM air feed may be available to the power cycle at an efficiency
(LHV) of about 60% since it produces power in the gas turbine
followed by the power produced in the steam system. The remaining
heat from the duct firing used to raise the temperature of the gas
turbine exhaust to 875.degree. C. may only be available to produce
power at about 40% efficiency in the Rankine steam cycle alone.
This means that duct firing in the gas turbine exhaust entering the
HRSG to allow indirect heating of the ITM feed air stream is a
grossly inefficient use of the H.sub.2 or (H.sub.2+CO) fuel
generated in the gasification system. A detailed analysis of the
performance of the duct fired HRSG with indirect heating of the ITM
feed air stream is given in the examples.
[0023] In all of these cases, in order to produce the diluted fuel
gas stream at typically 450.degree. C., heat is recovered from the
non-permeate ITM stream by cooling from 850.degree. C. and
rejecting this heat into the steam system where the maximum
efficiency for the recovered heat to produce power is typically 40%
and even with supercritical steam conditions will not exceed 44%.
For a General Electric 9FA gas turbine linked to a coal based
GE/Texaco quench gasifier, the duct firing heat load based on a
normal gas turbine exit temperature of 600.degree. C. would be 168
MW. The duct firing produces a hot gas for ITM feed air heating
with a heat load requirement of 52.7 MW. Thus, an extra 115.2 MW of
fuel gas must be consumed producing power at say 42% instead of 60%
efficiency--a loss of 20.7 MW of electrical power.
[0024] The proposed prior art process uses the pressurized ITM
non-permeate stream as a diluent for the H.sub.2 or (H.sub.2+CO)
fuel gas stream to reduce the combustion temperature to minimise
NOX formation and to maximise turbine flow to fully load the
turbine. There is a very significant hazard in this proposal since
it is necessary to ensure that there will never be any chance of an
O.sub.2 concentration arising which would exceed the lower
flammable limit for the mixture and cause an explosion. If we take
a conservative view that the ITM O.sub.2 recovery for the direct
combustion case with a separate adiabatic air compressor was 70%
then the O.sub.2 concentration in the proposed diluent would be
about 6% O.sub.2. This is far too high for safe operation. A level
of less than 1% has been accepted in previous IGCC cases, where
N.sub.2 from a cryogenic ASU is mixed with fuel gases derived from
a gasifier, as the maximum O.sub.2 concentration permissible in the
diluent N.sub.2 stream
[0025] Integration of ITM O.sub.2 production modules with existing
unmodified gas turbines may include an external air compressor
supplying part or all of the air flow for O.sub.2 production. In
some implementations, the proposed system may allow all or
substantially all of the fuel gas combustion heat used for air
preheating to be recovered at the gas turbine combustion heat input
level so that recovered heat can produce electrical power at 55% to
60% net efficiency. Alternatively or in addition, the fuel gas may
be effectively diluted with a nitrogen rich diluent and supplied at
a temperature below 500.degree. C. without loss of efficiency
caused by transferring heat to the steam system. In addition, the
oxygen content of the diluent stream may be reduced to a
concentration at the ITM exit to reduce safety hazards when diluent
and H.sub.2 or (H.sub.2+CO) fuel gas at elevated temperature are
mixed. Also, the mixture of H.sub.2 or (H.sub.2+CO) fuel gas and
diluent may be within an LHV value for satisfactory combustion in a
gas turbine. The range may be for LHV values to be greater than
about 120 Btu/scf and that the diluted fuel gas mixture may be at
the maximum or otherwise an upper temperature allowed by the gas
turbine vendor.
[0026] In some implementations, an ITM O.sub.2 generation system
coupled to a standard gas turbine modified to burn H.sub.2 or
H.sub.2 rich fuel gas may be designed to include or execute one or
more of the following: (1) the oxygen production may be sufficient
to provide the O.sub.2 required for a gasifier or other process
consuming O.sub.2 (e.g., an IGCC process which converts a
carbonaceous or hydro-carbonaceous fuel to H.sub.2 or a H.sub.2
rich fuel gas with or without carbon dioxide capture and provides
sufficient clean fuel gas to power the gas turbine); (2) the
H.sub.2 fuel gas may be diluted with inert gas to reduce NOX level
and provide sufficient fuel gas to load the gas turbine but the LHV
heating value of the fuel gas may be above 120 Btu/scf to favour
combustion; (3) all or substantially all of the fuel gas used for
heating air to ITM operating temperature of typically 850.degree.
C. may be used as part of the fuel gas input to the gas turbine
even in the case when the ITM feed air stream is provided from a
separate air compressor; (4) to maximize or otherwise increase
O.sub.2 production from a given ITM feed air flow the air may be
heated indirectly; (5) the oxygen permeate and non-permeate streams
leaving the ITM unit may be transfer the maximum or increased
quantity of heat to or become part of the feed streams to either
the gas turbine combustor or the upstream gasifier and, in some
cases, any high grade heat transferred to the steam system may be
minimized or otherwise reduces; (6) the maximum or upper
temperature of the diluted H.sub.2 feed gas to the gas turbine
combustor may be 450.degree. C. and the maximum or upper O.sub.2
feed gas temperature to the gasifier may be 350.degree. C.; (7) the
O.sub.2 content of the diluent to the H.sub.2 fuel gas may be 2.5%
O.sub.2 to prevent possible ignition and explosion (e.g., O.sub.2
content below 1% molar); (8) depending on the amount of side-draw
air that can be withdrawn from the gas turbine, an air compressor
in parallel to the gas turbine compressor may be included to
make-up air feed to the ITM module. One or more of these objectives
may be achieved by the following ITM gas turbine integration.
[0027] The ITM module may be fed with adiabatically compressed air
drawn from the gas turbine air compressor discharge or a separate
air compressor or both together. The gas turbine side-draw air
stream which may form part or all of the air feed to the ITM module
may be raised in pressure so that the non-permeate stream which is
depleted in O.sub.2 is at a sufficiently high pressure to be mixed
with the gas turbine fuel gas stream, which passes through a
regulation system and through the burner nozzles before mixing with
the main gas turbine compressed air stream. In practice, the
pressure may be raised in a single stage compressor by 2 bar to 5
bar. Air compressed isothermally in a separate air compressor may
be heated by indirect heat transfer with the O.sub.2 permeate
stream from the ITM module in a first stage heat exchanger then
mixed with any side-draw air from the gas turbine compressor
discharge following compression. The non-permeate stream leaving
the ITM module may be raised to a temperature in the range
850.degree. C. to 950.degree. C. in a directly fired combustor
using diluted fuel gas. The total ITM feed air stream may then be
heated by indirect heat transfer in a heat exchanger against the
heated ITM non-permeate stream to raise its temperature in a range
from about 800.degree. C. to about 900.degree. C. The ITM
non-permeate stream may be heated by direct combustion of fuel gas
to raise the temperature to a level sufficiently high to achieve
two objectives: (2) to heat the ITM inlet air to 850.degree. C.;
and (2) to achieve an exit temperature from the air pre-heater for
the non-permeate stream to ensure that when all or part of this
stream is used as diluent for the fuel gas, which is close to
ambient temperature the resulting mixed temperature is at
450.degree. C. By partially removing O.sub.2 from the non-permeate
stream by oxidising fuel gas in the combustor, the resultant
O.sub.2 concentration may be kept below 2.5% O.sub.2 (e.g., below
1% molar).
[0028] There may be an excess of non-permeate gas which is not
needed or otherwise used for fuel gas dilution. This may be reduced
in pressure and added to the gas turbine air compressor discharge
or injected into the mixing section of the gas turbine combustors.
Optionally, the two heat exchangers may be in parallel rather than
in series. In a parallel arrangement the oxygen permeate stream
which is at sub-atmospheric pressure, typically about 0.3 to 0.8
bar, may be passed through a heat exchanger which heats part of the
air feed to the ITM unit. In a typical application, part of the ITM
feed air may be heated to 820.degree. C. against O.sub.2 at
850.degree. C. and the parallel heat exchanger may heat the
remaining ITM air feed stream against heated non-permeate stream to
a higher temperature than 850.degree. C. so that total air stream
after mixing was at about 850.degree. C. The low pressure O.sub.2
stream may then pass into a second heat exchanger which heats the
compressed O.sub.2 feed for the gasifier to about 350.degree.
C.
[0029] The system shown in FIG. 1 uses a gas turbine 1 coupled to
an electric generator 2 which is also coupled to a steam turbine 3.
The steam is generated in a heat recovery steam generator 4 which
includes boiler feed-water treatment and pumps and which is heated
by the gas turbine exhaust stream 5. Part of the air which has been
adiabatically compressed in the gas turbine compressor section 6 at
18 bar is compressed to 22 bar in compressor 7. The air stream is
heated in the parallel heat exchangers 8 and 9 to form a mixed
steam 10 with a temperature of 850.degree. C. The air enters an ITM
module 11 where an oxygen stream 12 is separated at a pressure of,
for example, 0.6 bar leaving a non-permeate stream 13. A fuel gas
stream 14 is divided into two streams. One stream 15 is the fuel
for the gas turbine combustor 16 and the second stream 17 is the
fuel for a combustor 18 in which the non-permeate stream 13 is
heated to 1380.degree. C. and leaves as stream 19 with an oxygen
content of, for example, 1% molar. The oxygen permeate stream cools
to 500.degree. C. in heat exchanger 9 and the non-permeate stream
cools to 860.degree. C. The oxygen stream 20 leaving 9 is cooled in
heat exchanger 21 where it heats the product oxygen stream 22 at 65
bar to 350.degree. C. The intercooled compressor 23 raises the
oxygen pressure from 0.35 bar to 65 bar. The non-permeate stream 29
leaving 9 is cooled in heat exchanger 24 to a temperature at which
part 25 can be mixed with the fuel gas stream 15 to give 50% fuel
gas+50% diluent fuel gas stream which is at a mixed temperature
which is below a maximum or predefined fuel stream inlet
temperature specified by the gas turbine vendor which in this case
is 450.degree. C. The remaining non-permeate stream 26 is mixed
with the inlet gas stream to the gas turbine compressor section 27.
Steam can be generated and/or superheated in heat exchanger 24 to
increase the power produced in the steam turbine 3. Note that in
order to simultaneously achieve the required temperature and
composition of the mixed fuel gas stream 28 which is entering the
gas turbine combustor 16, the stream 29 can be divided so that part
30 bypasses the heat exchanger 24.
[0030] The system shown in FIG. 2 is very similar to the system
shown in FIG. 1 with the addition of an external intercooled air
compressor 34 which produces half of the total ITM feed air flow 10
as stream 35 at a pressure 0.5 bar higher than the pressure of the
gas turbine air side-draw flow leaving the compressor 7 and at a
temperature of 75.degree. C. Stream 35 is heated to 192.degree. C.
in heat exchanger 9 which cools the oxygen permeate stream 12 at
0.6 bar from the ITM module 11 to 500.degree. C. from 850.degree.
C. The oxygen stream 20 leaving heat exchanger 9 is used in heat
exchanger 21 to heat the compressed oxygen stream at 65 bar from
the compressor 23 to a temperature of 350.degree. C. The externally
compressed air stream 36 leaving heat exchanger 9 is heated to
about 500.degree. C. in heat exchanger 8 and at this point it is
mixed with the gas turbine side-draw air stream which is also at
about 500.degree. C. The mixed total air feed stream is then heated
to 850.degree. C. The heating medium in heat exchanger 8 is as
before the heated non-permeate stream from the ITM module. The
remaining parts of the system are identical to those shown in FIG.
1.
[0031] An approximate scaling exercise REF 3 is based on published
data for Pittsburgh
[0032] No 8 coal used in an IGCC system with carbon monoxide sour
shift reactors and 75% CO2 capture. The system may use GE 9FA gas
turbines, cryogenic O.sub.2 production and a Texaco quench gasifier
with CO.sub.2 capture. Fuel gas dilution may be with steam and some
CO.sub.2. The base case performance follows:
[0033] Gross power (gasturbine+steam turbine+expansion
turbine)=481Mw
[0034] Cryogenic ASU power=47.7Mw
[0035] Internal power consumption=14.1Mw
[0036] Net power output=419.2Mw
[0037] Net efficiency (LHV)=39%
Using the system described above with an ITM module and an oxygen
compressor in place of the cryogenic oxygen plant may give the
following results:
[0038] 1. All ITM air taken from the gas turbine air compressor
outlet [0039] Net Power=466.6Mw [0040] Net Efficiency=40.52%
[0041] 2. Half ITM air from the gas turbine and half from a
separate air compressor [0042] Net power=462.3Mw [0043] Net
efficiency=41.37%
[0044] 3. All ITM air taken from a separate air compressor [0045]
Net power=448.4Mw [0046] Net efficiency=41.2%.
[0047] A number of embodiments of the invention have been
described. Nevertheless, it will be understood that various
modifications may be made without departing from the spirit and
scope of the invention. For example, an approximate scaling
exercise based on published data for coal IGCC using 9FA gas
turbines, cryo O.sub.2 and a Texaco quench gasifier with CO.sub.2
capture showed an efficiency increase (LHV basis) from 39% to
41.65% with a power output increase of 6.8%. Accordingly, other
embodiments are within the scope of the following claims.
* * * * *