U.S. patent application number 15/339970 was filed with the patent office on 2017-05-18 for fuel combusting method with co2 capture.
The applicant listed for this patent is ExxonMobil Research and Engineering Company. Invention is credited to Franklin F. MITTRICKER, Narasimhan SUNDARAM, Hans THOMANN.
Application Number | 20170138236 15/339970 |
Document ID | / |
Family ID | 57354436 |
Filed Date | 2017-05-18 |
United States Patent
Application |
20170138236 |
Kind Code |
A1 |
SUNDARAM; Narasimhan ; et
al. |
May 18, 2017 |
FUEL COMBUSTING METHOD WITH CO2 CAPTURE
Abstract
A method for capturing emissions from a fuel combustion process
comprising: providing a fuel to a combustor on a gas turbine,
providing an oxidant to the combustor, combusting the fuel and the
oxidant in the combustor to produce an exhaust gas, passing at
least a portion of the exhaust gas to one or more catalyst beds.
The one or more catalyst beds promote a reaction which consumes CO
and produces CO.sub.2 and adsorb CO.sub.2. Pressure at the catalyst
beds is reduced by outputting a blow down stream from the catalyst
beds and then CO.sub.2 is purged from the one or more catalyst beds
with a regenerant stream to create a product stream.
Inventors: |
SUNDARAM; Narasimhan;
(Annandale, NJ) ; THOMANN; Hans; (Bedminster,
NJ) ; MITTRICKER; Franklin F.; (Jamul, CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
ExxonMobil Research and Engineering Company |
Annandale |
NJ |
US |
|
|
Family ID: |
57354436 |
Appl. No.: |
15/339970 |
Filed: |
November 1, 2016 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
62256366 |
Nov 17, 2015 |
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
B01D 2257/502 20130101;
B01D 53/864 20130101; B01D 53/047 20130101; B01D 2256/22 20130101;
Y02A 50/2342 20180101; Y02C 10/04 20130101; Y02C 10/08 20130101;
F01N 3/0857 20130101; F01N 3/0885 20130101; B01D 53/62
20130101 |
International
Class: |
F01N 3/08 20060101
F01N003/08 |
Claims
1. A method for capturing emissions from a fuel combustion process
comprising: providing a fuel to a combustor on a gas turbine;
providing an oxidant to the combustor; combusting the fuel and the
oxidant in the combustor to produce an exhaust gas; passing at
least a portion of the exhaust gas to one or more catalyst beds,
wherein the one or more catalyst beds: promote a reaction which
consumes CO and produces CO.sub.2; and adsorb CO.sub.2; reducing
the pressure at the catalyst beds by outputting a blow down stream
from the catalyst beds; and purging CO.sub.2 from the one or more
catalyst beds with a regenerant stream to create a recovery
stream.
2. The method of claim 1, further comprising cooling and condensing
the recovery stream to recover energy and concentrated
CO.sub.2.
3. The method of claim 1, wherein the one or more catalyst beds
comprise at least two catalyst beds.
4. The method of claim 3, further comprising cycling the adsorption
of CO.sub.2 by the at least two catalyst beds to allow regeneration
of at least one catalyst bed while at least one other bed continues
to adsorb CO.sub.2.
5. The method of claim 1, further comprising passing the product
stream to one or more non-catalyst adsorbent beds wherein the one
or more non-catalyst adsorbent beds adsorb CO.sub.2.
6. The method of claim 1, further comprising passing both a second
portion of the exhaust stream and the recovery stream to one or
more non-catalyst adsorbent beds.
7. The method of claim 1, wherein the regenerant stream comprises
at least one of N.sub.2, steam, or liquid water.
8. The method of claim 1, wherein the regenerant stream comprises
liquid water.
9. A system for capturing emissions from a fuel combustion process
comprising: a combustor on a gas turbine configured to receive fuel
and an oxidant; an exhaust gas outlet to release exhaust gas from
the combustor; one or more catalyst beds positioned downstream from
a portion of the exhaust gas outlet, wherein the one or more
catalyst beds: promote a reaction which consumes CO and produces
CO.sub.2; adsorb CO.sub.2; and wherein the one or more catalyst
beds further comprise: a blow down output feed which outputs a blow
down stream to reduce the pressure in the one or more catalyst
beds; a first purge input feed which receives regenerant stream; a
first purge output feed which outputs a recovery stream for purging
CO.sub.2 from the one or more catalyst beds.
10. The system of claim 9, further comprising a heat exchanger and
condenser downstream from the recovery stream to recover energy and
concentrated CO.sub.2.
11. The system of claim 9, wherein the one or more catalyst beds
comprise at least two catalyst beds.
12. The system of claim 11, wherein adsorption of CO.sub.2 by the
at least two catalyst beds is cycled to allow regeneration of at
least one catalyst bed while at least one other bed continues to
adsorb CO.sub.2.
13. The system of claim 9, further comprising one or more
non-catalyst adsorbent beds downstream from the recovery stream
wherein the one or more non-catalyst adsorbent beds adsorb
CO.sub.2.
14. The system of claim 9, wherein the regenerant stream comprises
at least one of N.sub.2, steam, or liquid water.
15. The system of claim 9, wherein the regenerant stream comprises
liquid water.
16. A method for capturing emissions from a hydrogen generation
fuel combustion process comprising: providing a fuel to a fuel
reforming reactor; providing an oxidant to the fuel reforming
reactor; combusting the fuel and the oxidant in the fuel reforming
reactor to produce an exhaust gas; passing at least a portion of
the exhaust gas to one or more catalyst beds, wherein the one or
more catalyst beds: promote a reaction which consumes CO and
produces CO.sub.2; and adsorb CO.sub.2; reducing the pressure at
the catalyst beds by outputting a blow down stream from the
catalyst beds; and purging CO.sub.2 from the one or more catalyst
beds with a regenerant stream to create a recovery stream; wherein
the one or more catalyst beds are configured to operate on a fast
cycle on the order of seconds and are connected by rotary or
non-rotary valving means.
17. The method of claim 17, wherein the regenerant stream comprises
at least one of N.sub.2, CO.sub.2, steam, or liquid water.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority to U.S. Provisional
Application Ser. No. 62/256,366 filed on Nov. 17, 2015, herein
incorporated by reference in its entirety.
FIELD
[0002] The present disclosure relates generally to low-emission
power generation systems. More particularly, the present disclosure
relates to systems and methods for changing the composition of
components in exhaust gases from gas turbine systems.
BACKGROUND
[0003] This section is intended to introduce various aspects of the
art, which may be associated with exemplary embodiments of the
present techniques. This discussion is believed to assist in
providing a framework to facilitate a better understanding of
particular aspects of the present techniques. Accordingly, it
should be understood that this section should be read in this
light, and not necessarily as admissions of prior art.
[0004] The combustion of fuel within a combustor, e.g., integrated
with a gas turbine, can be controlled by monitoring the temperature
of the exhaust gas. Under full load conditions, typical gas
turbines adjust the amount of fuel introduced to a number of
combustors in order to reach a desired combustion gas or exhaust
gas temperature. Conventional combustion turbines control the
oxidant introduced to the combustors using inlet guide vanes. Under
partial load conditions, the amount of oxidant introduced to the
combustor is reduced and the amount of fuel introduced is again
controlled to reach the desired exhaust gas temperature. Further,
at partial load, the efficiency of gas turbines drops because the
ability to reduce the amount of oxidant is limited by the inlet
guide vanes, which are only capable of slightly reducing the flow
of oxidant. Further, the oxidant remains at a constant lower flow
rate when the inlet guide vanes are in their flow restricting
position. The efficiency of the gas turbine then drops when it is
at lower power production because to make that amount of power with
that mass flow a lower expander inlet temperature is required.
Moreover, existing oxidant inlet control devices may not allow fine
flow rate control and may introduce large pressure drops with any
restriction on the oxidant flow. With either of these approaches to
oxidant control, there are potential problems with lean blow out at
partial load or reduced pressure operations.
[0005] Controlling the amount of oxidant introduced to the
combustor can be desirable when an objective is to capture carbon
dioxide (CO.sub.2) from the exhaust gas. Current carbon dioxide
capture technology is expensive due to several reasons. One reason
is the low pressure and low concentration of carbon dioxide in the
exhaust gas. The carbon dioxide concentration, however, can be
significantly increased from about 4% to greater than 10% by
operating the combustion process under substantially stoichiometric
conditions. Further, a portion of the exhaust gas may be recycled
to the combustor as a diluent in order to control the temperature
of the gas within the combustor and of the exhaust gas. Also, any
unused oxygen in the exhaust gas may be a contaminant in the
captured carbon dioxide, restricting the type of solvents that can
be utilized for the capture of carbon dioxide.
[0006] In many systems, an oxidant flow rate may be reduced by
altering the operation of a separate oxidant system. For example,
an independent oxidant compressor may be throttled back to a slower
operating speed thereby providing a decreased oxidant flow rate.
However, the reduction in compressor operating speed generally
decreases the efficiency of the compressor. Additionally,
throttling the compressor may reduce the pressure of the oxidant
entering the combustor. In contrast, if the oxidant is provided by
the compressor section of the gas turbine, reducing the speed is
not a variable that is controllable during power generation. Large
gas turbines that are used to produce 60 cycle power are generally
run at 3600 rpm. Similarly, to produce 50 cycle power the gas
turbine is often run at 3000 rpm. In conventional gas turbine
combustor operations the flow of oxidant into the combustor may not
warrant significant control because the excess oxidant is used as
coolant in the combustion chamber to control the combustion
conditions and the temperature of the exhaust gas. A number of
studies have been performed to determine techniques for controlling
combustion processes in gas turbines.
[0007] International Patent Application Publication No.
W0/2010/044958 by Mittricker et al. discloses methods and systems
for controlling the products of combustion, for example, in a gas
turbine system. One embodiment includes a combustion control system
having an oxygenation stream substantially comprising oxygen and
CO.sub.2 and having an oxygen to CO.sub.2 ratio, then mixing the
oxygenation stream with a combustion fuel stream and combusting in
a combustor to generate a combustion products stream having a
temperature and a composition detected by a temperature sensor and
an oxygen analyzer, respectively. The data from the sensors are
used to control the flow and composition of the oxygenation and
combustion fuel streams. The system may also include a gas turbine
with an expander and having a load and a load controller in a
feedback arrangement.
[0008] International Patent Application Publication No.
W0/2009/120779 by Mittricker et al. discloses systems and methods
for low emission power generation and hydrocarbon recovery. One
system includes integrated pressure maintenance and miscible flood
systems with low emission power generation. Another system provides
for low emission power generation, carbon sequestration, enhanced
oil recovery (EOR), or carbon dioxide sales using a hot gas
expander and external combustor. Another system provides for low
emission power generation using a gas power turbine to compress air
in the inlet compressor and generate power using hot carbon dioxide
laden gas in the expander.
[0009] U.S. Pat. No. 4,858,428 to Paul discloses an advanced
integrated propulsion system with total optimized cycle for gas
turbine. Paul discloses a gas turbine system with integrated high
and low pressure circuits having a power transmission for
extracting work from one of the circuits, the volume of air and
fuel to the respective circuits being varied according to the power
demand monitored by a microprocessor. The turbine system has a low
pressure compressor and a staged high pressure compressor with a
combustion chamber and high pressure turbine associated with the
high pressure compressor. A combustion chamber and a low pressure
turbine are associated with the low pressure compressor, the low
pressure turbine being staged with the high pressure turbine to
additionally receive gases expended from the high pressure turbine
and a microprocessor to regulate air and gas flows between the
compressor and turbine components in the turbine system.
[0010] U.S. Pat. No. 4,271,664 to Earnest discloses a turbine
engine with exhaust gas recirculation. The engine has a main power
turbine operating on an open-loop Brayton cycle. The air supply to
the main power turbine is furnished by a compressor independently
driven by the turbine of a closed-loop Rankine cycle which derives
heat energy from the exhaust of the Brayton turbine. A portion of
the exhaust gas is recirculated into the compressor inlet during
part-load operation.
[0011] U.S. Patent Application Publication No. 2009/0064653 by
Hagen et al. discloses partial load combustion cycles. The part
load method controls delivery of diluent fluid, fuel fluid, and
oxidant fluid in thermodynamic cycles using diluent to increase the
turbine inlet temperature and thermal efficiency in part load
operation above that obtained by relevant art part load operation
of Brayton cycles, fogged Brayton cycles, or cycles operating with
some steam delivery, or with maximum steam delivery.
[0012] U.S. Pat. No. 5,355,668 to Weil et al. discloses a
catalyst-bearing component of a gas turbine engine. Catalytic
materials are formed on components in the gas flow path of the
engine, reducing emissions of carbon monoxide and unburned
hydrocarbons. The catalytic materials are selected from the noble
metals and transition metal oxides. The portions of the gas t1ow
path where such materials are applied can include the combustor,
the turbine, and the exhaust system. The catalytic coating can be
applied in conjunction with a thermal barrier coating system
interposed between a substrate component and the catalytic
coating.
[0013] While some past efforts to control the oxidant flow rate
have implemented oxidant inlet control devices, such systems
disclosed a control of all of the combustors together, failing to
account for differences between combustors. Further, the systems
were limited in their ability to finely tune the oxidant flow rate.
As a result, the concentration of certain gases in the exhaust was
higher than desirable.
SUMMARY
[0014] Certain embodiments of the present invention are directed to
methods for capturing emissions from a fuel combustion process
comprising: providing a fuel to a combustor on a gas turbine,
providing an oxidant to the combustor, combusting the fuel and the
oxidant in the combustor to produce an exhaust gas, and passing at
least a portion of the exhaust gas to one or more catalyst beds.
The one or more catalyst beds promote a reaction which consumes CO
and produces CO.sub.2 and adsorb CO.sub.2. After passing the
exhaust gas to the catalyst beds, the pressure at the catalyst beds
is reduced by outputting a blow down stream from the catalyst beds
and CO.sub.2 is purged from the one or more catalyst beds with a
regenerant stream to create a recovery stream.
[0015] The invention may be embodied by numerous other devices and
methods. The description provided herein, when taken in conjunction
with the annexed drawings, discloses examples of the invention.
Other embodiments, which incorporate some or all steps as taught
herein, are also possible.
BRIEF DESCRIPTION OF THE DRAWINGS
[0016] Referring to the drawings, which form a part of this
disclosure:
[0017] FIG. 1 schematically shows a diagram of a gas turbine system
that includes a gas turbine;
[0018] FIG. 2 schematically shows a gas turbine system that
includes an HRSG and catalyst beds on the exhaust stream from the
expander exhaust section;
[0019] FIG. 3 schematically shows a diagram of a configuration of
catalyst beds and non-catalyst beds on the exhaust stream from the
turbine and HRSG;
[0020] FIG. 4A and FIG. 4B show graphical depictions of a
simulation showing the relationship between the concentration of
oxygen and carbon monoxide;
[0021] FIG. 5 shows a block diagram of a method for adjusting fuel
and oxidant levels to the combustors based on readings from an
array of sensors;
[0022] FIG. 6 shows a block diagram of a plant control system that
may be used to control the oxidant and fuel to the combustors in a
gas turbine engine; and
[0023] FIG. 7 shows a schematic of a simulated gas turbine system
that illustrates the use of two catalyst beds in a HRSG to reduce
the concentration of selected components in the exhaust stream.
DETAILED DESCRIPTION
[0024] In the following detailed description section, specific
embodiments of the present techniques are described. However, to
the extent that the following description is specific to a
particular embodiment or a particular use of the present
techniques, this is intended to be for exemplary purposes only and
simply provides a description of the exemplary embodiments.
Accordingly, the techniques are not limited to the specific
embodiments described below, but rather, include all alternatives,
modifications, and equivalents falling within the true spirit and
scope of the appended claims.
[0025] At the outset, for ease of reference, certain terms used in
this application and their meanings as used in this context are set
forth. To the extent a term used herein is not defined below, it
should be given the broadest definition persons in the pertinent
art have given that term as reflected in at least one printed
publication or issued patent. Further, the present techniques are
not limited by the usage of the terms shown below, as all
equivalents, synonyms, new developments, and terms or techniques
that serve the same or a similar purpose are considered to be
within the scope of the present claims.
[0026] A "combined cycle power plant" uses both steam and gas
turbines to generate power. The gas turbine operates in an open or
semi-open Brayton cycle, and the steam turbine operates in a
Rankine cycle powered by the heat from the gas turbine. These
combined cycle gas/steam power plants generally have a higher
energy conversion efficiency than gas or steam only plants. A
combined cycle plant's efficiencies can be as high as 50% to 60%.
The higher combined cycle efficiencies result from synergistic
utilization of a combination of the gas turbine with the steam
turbine. Typically, combined cycle power plants utilize heat from
the gas turbine exhaust to boil water to generate steam. The
boilers in typical combined cycle plants can be referred to as heat
recovery steam generator (HRSG). The steam generated is utilized to
power a steam turbine in the combined cycle plant. The gas turbine
and the steam turbine can be utilized to separately power
independent generators, or in the alternative, the steam turbine
can be combined with the gas turbine to jointly drive a single
generator via a common drive shaft.
[0027] A diluent is a gas that is primarily used to reduce the
combustor temperatures that result from the combustion of a fuel
and oxidant. A diluent may be used to lower the concentration of
oxidant or fuel (or both) that is fed to a gas turbine and/or to
dilute the products of combustion. The diluent may be an excess of
nitrogen, CO.sub.2, combustion exhaust, or any number of other
gases. In embodiments, a diluent may also provide cooling to a
combustor and/or other parts of the gas turbine.
[0028] As used herein, a "compressor" includes any type of
equipment designed to increase the pressure of a working fluid, and
includes any one type or combination of similar or different types
of compression equipment. A compressor may also include auxiliary
equipment associated with the compressor, such as motors, and drive
systems, among others. The compressor may utilize one or more
compression stages, for example, in series. Illustrative
compressors may include, but are not limited to, positive
displacement types, such as reciprocating and rotary compressors
for example, and dynamic types, such as centrifugal and axial flow
compressors, for example. For example, a compressor may be a first
stage in a gas turbine engine, as discussed in further detail
below.
[0029] A "control system" typically comprises one or more physical
system components employing logic circuits that cooperate to
achieve a set of common process results. In an operation of a gas
turbine engine, the objectives can be to achieve a particular
exhaust composition and temperature. The control system can be
designed to reliably control the physical system components in the
presence of external disturbances, variations among physical
components due to manufacturing tolerances, and changes in inputted
set-point values for controlled output values. Control systems
usually have at least one measuring device, which provides a
reading of a process variable, which can be fed to a controller,
which then can provide a control signal to an actuator, which then
drives a final control element acting on, for example, an oxidant
stream. The control system can be designed to remain stable and
avoid oscillations within a range of specific operating conditions.
A well-designed control system can significantly reduce the need
for human intervention, even during upset conditions in an
operating process.
[0030] An "equivalence ratio" refers to the mass ratio of fuel to
oxygen entering a combustor divided by the mass ratio of fuel to
oxygen when the ratio is stoichiometric. A perfect combustion of
fuel and oxygen to form CO.sub.2 and water would have an
equivalence ratio of 1. A too lean mixture, e.g., having more
oxygen than fuel, would provide an equivalence ratio less than 1,
while a too rich mixture, e.g., having more fuel than oxygen, would
provide an equivalence ratio greater than 1.
[0031] A "fuel" includes any number of hydrocarbons that may be
combusted with an
[0032] oxidant to power a gas turbine. Such hydrocarbons may
include natural gas, treated natural gas, kerosene, gasoline, or
any number of other natural or synthetic hydrocarbons.
[0033] A "gas turbine" engine operates on the Brayton cycle. If the
exhaust gas is vented, this is termed an open Brayton cycle, while
recycling at least a portion of the exhaust gas gives a semi-open
Brayton cycle. In a semi-open Brayton cycle, at least fuel and
oxidant are added to the system to support internal combustion and
a portion of the products of combustion are vented or extracted. In
a closed Brayton cycle, all of the exhaust is recycled and none is
vented or extracted and heat is added to the system by external
combustion or another means. As used herein, a gas turbine
typically includes a compressor section, a number of combustors,
and a turbine expander section. The compressor may be used to
compress an oxidant, which is mixed with a fuel and channeled to
the combustors. The mixture of fuel and oxidant is then ignited to
generate hot combustion gases. The combustion gases are channeled
to the turbine expander section which extracts energy from the
combustion gases for powering the compressor, as well as producing
useful work to power a load. In embodiments discussed herein, the
oxidant may be provided to the combustors by an external
compressor, which may or may not be mechanically linked to the
shaft of the gas turbine engine. Further, in embodiments, the
compressor section may be used to compress a diluent, such as
recycled exhaust gases, which may be fed to the combustors as a
coolant.
[0034] A "heat recovery steam generator" or HRSG is a heat
exchanger or boiler that recovers heat from a hot gas stream. It
produces steam that can be used in a process or used to drive a
steam turbine. A common application for an HRSG is in a
combined-cycle power plant, where hot exhaust from a gas turbine is
fed to the HRSG to generate steam which in turn drives a steam
turbine. This combination produces electricity more efficiently
than either the gas turbine or steam turbine alone. As used herein,
an HRSG may include any number of heat recovery units in addition
to, or instead of, an HRSG by itself.
[0035] A "hydrocarbon" is an organic compound that primarily
includes the elements hydrogen and carbon, although nitrogen,
sulfur, oxygen, metals, or any number of other elements may be
present in small amounts. As used herein, hydrocarbons generally
refer to components found in raw natural gas, such as CH.sub.4,
C.sub.2H.sub.2, C.sub.2H.sub.4, C.sub.2H.sub.6, C.sub.3 isomers,
C.sub.4 isomers, benzene, and the like.
[0036] An "oxidant" is a gas mixture that can be flowed into the
combustors of a gas turbine engine to combust a fuel. As used
herein, the oxidant may be oxygen mixed with any number of other
gases as diluents, including CO.sub.2, N.sub.2, air, combustion
exhaust, and the like.
[0037] A "sensor" refers to any device that can detect, determine,
monitor, record, or otherwise sense the absolute value of or a
change in a physical quantity. A sensor as described herein can be
used to measure physical quantities including, temperature,
pressure, O.sub.2 concentration, CO concentration, CO.sub.2
concentration, flow rate, acoustic data, vibration data, chemical
concentration, valve positions, or any other physical data.
[0038] "Pressure" is the force exerted per unit area by the gas on
the walls of the volume. Pressure can be shown as pounds per square
inch (psi). "Atmospheric pressure" refers to the local pressure of
the air. "Absolute pressure" (psia) refers to the sum of the
atmospheric pressure (14.7 psia at standard conditions) plus the
gage pressure (psi g). "Gauge pressure" (psig) refers to the
pressure measured by a gauge, which indicates only the pressure
exceeding the local atmospheric pressure (i.e., a gauge pressure of
0 psig corresponds to an absolute pressure of 14.7 psia). The term
"vapor pressure" has the usual thermodynamic meaning. For a pure
component in an enclosed system at a given pressure, the component
vapor pressure is essentially equal to the total pressure in the
system.
[0039] "Substantial" when used in reference to a quantity or amount
of a material, or a specific characteristic thereof, refers to an
amount that is sufficient to provide an effect that the material or
characteristic was intended to provide. The exact degree of
deviation allowable may in some cases depend on the specific
context.
Overview
[0040] Embodiments of the present invention provide a system and a
method for consuming carbon monoxide generated in the combustion in
a gas turbine engine. This is performed by a water gas shift
reaction, for example, in a catalyst bed located in a heat-recovery
steam generator (HRSG). The water gas shift reaction is a chemical
reaction between carbon monoxide and water vapor that forms carbon
dioxide and hydrogen as products. The water-gas shift reaction is a
predominant reaction given the relatively large quantity of water
vapor present in the exhaust from the gas turbine. In some
embodiments, such as in a stoichiometric exhaust gas recirculation
(SEGR) gas turbine, the exhaust is a recirculated low oxygen
content gas stream, which is used at least as a coolant gas in the
combustors. Typically, water vapor content of more than 10 volume
percent (>100k parts per million volume, ppmv) is present in the
recirculated low oxygen content gas stream while oxygen, carbon
monoxide and hydrogen are of the order of 1000 to 5000 ppmv. As a
result, the water-gas shift reaction is able to consume residual
carbon monoxide plus a similar quantity of water vapor to create
carbon dioxide and hydrogen at a higher conversion efficiency than
the competing oxidation reactions. The resulting low CO content
product gas may comprise as little as 1 or 2 ppm CO.
[0041] A moderate conversion efficiency may be acceptable, since
the high concentration of water vapor relative to the concentration
of carbon monoxide will still tend to force a high conversion. The
catalyst bed may be located in a moderate temperature zone of the
HRSG, e.g., in a zone of about 150.degree. C. to about 250.degree.
C. or 100.degree. C. to 400.degree. C., since lower temperature
zones of the HRSG are well suited for catalyst systems designed for
a water-gas shift reaction. Hydrogen formed in the reaction will
likely have a very low conversion efficiency to oxidization to
water vapor. Accordingly, the hydrogen may be recirculated within
the recirculated low oxygen content gas stream to the compressor
section of the SEGR gas turbine and then may either be extracted as
part of the product stream, used as part of the sealing and cooling
stream of the gas turbine hot gas path or transit to the combustor
where this hydrogen should be largely oxidized within the
combustors. The hydrogen part extracted as part of the product
stream should be easily oxidized to water vapor within the first
oxidation catalyst unit included within the product extraction
circuit. Overall, this arrangement should provide improved
conversion efficiency.
[0042] In some embodiments described herein, an oxidation catalyst
is used in a hot zone of the HRSG to oxidize carbon monoxide,
hydrogen, and unburned hydrocarbons with residual oxygen from the
gas turbine exhaust, forming carbon dioxide and water. A moderate
oxidizing conversion efficiency may be accepted in order to provide
a low pressure drop across a catalyst bed.
[0043] Sensors may be placed in the exhaust gas, the product gas,
or both to adjust the combustion conditions to control the amount
of CO, oxygen or other contaminants in the exhaust gas. For
example, the sensors may be located in a ring on an expander
exhaust, an inlet to the catalyst bed, an outlet from a catalyst
bed, or any combination. The sensors may include lambda sensors,
oxygen sensors, carbon monoxide sensors, and temperature sensors,
among others. Further, combinations of different types of sensors
may be used to provide further information.
[0044] In some embodiments, multiple sensors may be used to adjust
the conditions in individual combustors on the gas turbine. The
sensors may not have a one-to-one relationship to particular
combustors, but may be influenced by a particular combustor. The
response of various sensors may be related back to a particular
combustor, for example, using sum and difference algorithms that
may be based on swirl charts. Swirl charts relate patterns of
exhaust flow in an expander to combustors that may have contributed
to the exhaust flow at that point.
[0045] The use of individually controlled combustors may increase
the burn efficiency of a gas turbine engine, e.g., making the burn
closer to a one-to-one equivalence ratio. Such improvements in
efficiency may lower 0 2, unburned hydrocarbons, and carbon
monoxide in the exhaust. This may make the use of an oxidation
catalyst more problematic, as both reactants are present in small
amounts. However, the large amount of water vapor in the exhaust
can maintain a high rate of conversion of the CO in the water gas
shift reaction.
[0046] FIG. 1 is a schematic diagram of a gas turbine system 100
that includes a gas turbine engine 102. The gas turbine engine 102
may have a compressor 104 and a turbine expander 106 on a single
shaft 108. The gas turbine engine 102 is not limited to a single
shaft arrangement, as multiple shafts could be used, generally with
mechanical linkages or transmissions between shafts. In various
embodiments, the gas turbine engine 102 also has a number of
combustors 110 that feed hot exhaust gas to the expander, for
example, through lines 112. For example, a gas turbine 102 may have
2, 4, 6, 14, 18, or even more combustors 110, depending on the size
of the gas turbine 102.
[0047] The combustors 110 are used to burn a fuel provided by a
fuel source 114. An oxidant may be provided to each of the
combustors 110 from various sources. For example, in embodiments,
an external oxidant source 116, such as an external compressor, may
provide the oxidant to the combustors 110. In embodiments, an
oxidant or recycled exhaust gases 118, or a mixture thereof, may be
compressed in the compressor 104 and then provided to the
combustors 110. In other embodiments, such as when an external
oxidant source 116 is provided, the compressor 104 may be used to
compress only the recycled exhaust gas, which may be fed to the
combustors 110 for cooling and dilution of the oxidant.
[0048] The exhaust gas from the combustors 110 expands in the
turbine expander 106, creating mechanical energy. The mechanical
energy may power the compressor 104 through the shaft 108. Further,
a portion of the mechanical energy may be harvested from the gas
turbine as a mechanical power output 120, for example, to generate
electricity or to power oxidant compressors. The expanded exhaust
gas 122 may be vented, used for heat recovery, recycled to the
compressor 104, or used in any combinations thereof. In an
embodiment, the exhaust gas 122 is flowed through one or more
catalyst beds that include a water gas shift catalyst, and
oxidation catalyst, or both.
[0049] In some embodiments, the oxidant is metered to the
combustors 110 to control an equivalence ratio of the fuel to the
oxidant. The metering may be performed for all combustors 110
together, for example, by adjusting the fuel 114 and oxidant 116
sources, or each individual combustor 110. It will be apparent to
one of skill in the art that a stoichiometric burn, e.g., at an
equivalence ratio of 1, will be hotter than a non-stoichiometric
burn. Therefore, either excess oxidant or an added non-combustible
gas, such as a recycle exhaust gas, can be added to cool the
engine, preventing damage to the combustors 110 or the turbine
expander 106 from the extreme heat.
[0050] The use of recycled exhaust gas 122 provides a further
advantage in that the exhaust is deficient in oxygen, making it a
better material for enhanced oil recovery. Adjusting individual
combustors 110 may compensate for differences between the
combustors 110, improving the overall efficiency of the gas turbine
102.
Control of Combustors
[0051] FIG. 2 is a schematic of a gas turbine system 200 that can
be used to adjust the oxidant flow and/or fuel flow to the
combustors 110 of a gas turbine engine 102. The referenced units
are as generally discussed with respect to FIG. 1. The system 200
may adjust the amount of oxidant 116 provided to the combustors
110, for example, by adjusting the pressure, flow rate, or
composition of the oxidant 116. Similarly, the system 200 may
adjust the amount of fuel 114 provided to the combustors 110 by
adjusting the pressure, flow rate, or composition of the fuel 114.
In an embodiment, the oxidant flow to each individual combustor 110
may be adjusted by an oxidant flow adjusting device 202, such as a
valve, swirler, or mixing section in each combustor 110. An
actuator 204 can be used to adjust the oxidant flow adjusting
device 202. Similarly, the fuel flow 114 to each individual
combustor 110 may be adjusted.
[0052] A number of sensors 206 can be placed in an expander exhaust
section 208 of the gas turbine engine 102, for example, 5, 10, 15,
20, 25, 30 or more, sensors 206 may be placed in a ring around the
expander exhaust section 208. The number of sensors 206 may be
determined by the size of the gas turbine 102, the number of
combustors 110, or both. The sensors 206 may include oxygen
sensors, carbon monoxide sensors, temperature sensors, hydrogen
sensors, and the like. Examples of oxygen sensors can include
lambda and/or wideband zirconia-oxygen sensors, titania sensors,
galvanic, infrared, or any combination thereof. Examples of
temperature sensors can include thermocouples, resistive
temperature devices, infrared sensors, or any combination thereof.
Examples of carbon monoxide sensors can include oxide based film
sensors such as barium stannate and/or titanium dioxide. For
example, a carbon monoxide sensor can include platinum-activated
titanium dioxide, lanthanum stabilized titanium dioxide, and the
like. The choice of the sensors 206 may be controlled by the
response time, as the measurements are needed for real time control
of the system. The sensors 206 may also include combinations of
different types of sensors 206. The sensors 206 send a signal 210
back to the control system 212, which may be used to make fuel and
oxidant adjustment decisions for each, or all, of the combustors
110. Any number of physical measurements could be performed, for
example, the sensors 206 could be used to measure temperature,
pressure, CO concentration, 0 2 concentration, vibration, and the
like. Further, multiple sensors 206 could be used to measure
combinations of these parameters.
[0053] The control system 212 may be part of a larger system, such
as a distributed control system (DCS), a programmable logic
controller (PLC), a direct digital controller (DDC), or any other
appropriate control system. Further, the control system 212 may
automatically adjust parameters, or may provide information about
the gas turbine 102 to an operator who manually performs
adjustments. The control system 212 is discussed further with
respect to FIG. 7, below.
[0054] It will be understood that the gas turbine system 200 shown
in FIG. 2, and similar gas turbine systems depicted in other
figures, have been simplified to assist in explaining various
embodiments of the present techniques. Accordingly, in embodiments
of the present techniques, both the oxidant system 116 and the fuel
system 114, as well as the gas turbine systems themselves, can
include numerous devices not shown. Such devices can include flow
meters, such as orifice flow meters, mass flow meters, ultrasonic
flow meters, venturi flow meters, and the like. Other devices can
include valves, such as piston motor valves (PMVs) to open and
close lines, and motor valves, such as diaphragm motor valves
(DMVs), globe valves, and the like, to regulate flow rates.
Further, compressors, tanks, heat exchangers, and sensors may be
utilized in embodiments in addition to the units shown.
[0055] In the embodiment shown in FIG. 2, the compressor 104 may be
used to compress a stream 214, such as a recycled exhaust stream.
After compression, the stream 214 may be injected from a line 216
into the mixing section of the combustor 110. The stream 214 is not
limited to a pure recycle stream, as the injected stream 216 may
provide the oxidant to the combustor 110. The exhaust stream 218
from the expander exhaust section 208 may be used to provide the
recycle stream, as discussed further with respect to FIG. 2,
below.
Catalyst and Adsorbent Beds
[0056] The exhaust stream 218 may be passed through one or more
catalyst beds 308, for example, attached to the exhaust expander
section 208, located in an HRSG, located near an HSRG, or in other
places in the gas turbine system 200. Multiple catalyst beds may be
used in sequence. Generally, an oxidation and/or reduction catalyst
bed may be located in a high temperature zone and draw its heat
from, for example, an exhaust expander section 208 or a heat
recovery steam generator (HRSG), as discussed herein. Preferably,
the temperature of the catalyst beds reaches 375.degree. C. or a
sufficient temperature to enable the catalyzed reaction to
occur.
[0057] As illustrated in FIG. 2, when the exhaust stream 218 exits
the HRSG, it is passed to one or more catalyst beds 308. The
exhaust stream 218 may contain CO, CO2, N2, and/or methane. When
passed to the catalyst beds, CO in the exhaust stream 218 is
consumed by a reaction catalyzed by the catalyst beds and producing
CO.sub.2. The materials of the catalyst beds 308 may double as
adsorbents, adsorbing the newly formed CO.sub.2. When the catalyst
beds 308 have adsorbed some amount of CO.sub.2, the catalyst beds
308 are then purged to with a regenerant stream 309 to release the
CO.sub.2. The combined product of the regenerant stream and
adsorbed CO.sub.2 is released from the catalyst beds 308 in
recovery stream 311.
[0058] Adsorption of CO.sub.2 at the catalyst beds preferably
occurs at the pressure of the exhaust stream when it reaches the
catalyst beds 308. In order to purge the adsorbed CO.sub.2 from the
catalyst beds 308, the pressure at the catalyst beds 308 is reduced
by a blow down process. Once the pressure is adequately reduced at
the catalyst beds 308 to release the adsorbed CO.sub.2, the
regenerant stream 309 can be directed to the catalyst beds 308 for
effective purging.
[0059] The catalyst beds 308 operate at a high temperature and draw
their heat from, for example, the HSRG. A primary advantage of this
is that when purging the catalyst beds 308 with regenerant stream
309, the regenerant stream may comprise N.sub.2 or steam, but it
also may comprise liquid water. Because of the temperature at which
the beds are operated, when liquid water is introduced to the
catalyst beds 308, some heat from the catalyst beds 308 is
transferred to the liquid water to form steam. Therefore, energy
need not be extracted from another point on the power generation
cycle to extract steam for the purge, which is a particularly
economically taxing aspect of emissions capture.
[0060] When the regenerant stream 309 is passed to the catalyst
beds 308, the adsorbed CO.sub.2 on the catalyst beds 308 mixes with
the regenerant stream 309 and is released in recovery stream 311.
Regenerant stream 309 is passed to the catalyst beds 308 for a
sufficient time period or in a sufficient time period to
substantially release the adsorbed CO.sub.2 from the beds. The
resulting recovery stream 311 is a mixture of at least CO.sub.2 and
steam. Once recovery stream 311 has left the catalyst beds 308, the
recovery stream 311 may be cooled and condensed to isolate the
CO.sub.2 from the steam and recover energy from the steam.
[0061] Multiple beds can be used in the catalyst beds 308 where
typically every bed sequentially goes through the same cycle. When
a first bed satisfies a condition, the feed flow can be switched to
a second bed. These conditions may be any of the following: a
predetermined period of feed time has passed, the feed flow can be
stopped based on a predetermined schedule, based on detection of
breakthrough of one or more heavy components, based on adsorption
of the heavy component(s) corresponding to at least a threshold
percentage of the total capacity of the adsorbent, or based on any
other convenient criteria. The first bed can then be regenerated by
having the adsorbed gases released via a purge. To allow for a
continuous feed flow, a sufficient number of or catalyst beds are
preferably used so that the first bed is finished regenerating
prior to at least one other bed satisfying the condition for
switching beds.
[0062] In an alternative embodiment, as illustrated in FIG. 3,
there may be included additional non-catalyst beds to which the
exhaust stream is directed. As discussed above with respect to FIG.
2, a portion of the exhaust stream 218 may be directed to catalyst
beds 308. A second portion of the exhaust stream 218 and/or a
portion of the recovery stream 311 may additionally be directed to
non-catalyst beds for adsorption of CO.sub.2. When catalyst beds
308 react CO to form CO.sub.2 and that CO.sub.2 is subsequently
adsorbed and purged, the recovery stream 311 is concentrated with
CO.sub.2. By passing recovery stream 311 to non-catalyst adsorbent
beds, the CO.sub.2 content in the recovery stream 311 can further
be isolated and further concentrated. The non-catalyst beds
preferably undergo the same cycling processes as discussed above
with relation to the catalyst beds 308.
[0063] The sensors 206 are not limited to the expander exhaust
section 208, but may be in any number of other locations, instead
of or in addition to the expander exhaust section 208. For example,
the sensors 206 may be disposed in multiple rings around the
expander exhaust section 208. Further, the sensors 206 may be
separated into multiple rings by the type of sensor 206, for
example, with oxygen analyzers in one ring and temperature sensors
in another ring. Sensors 224 may also be located in the product gas
stream 222 from the catalyst beds 308.
[0064] The recovered carbon dioxide may be injected into a
subterranean reservoir for enhanced hydrocarbon recovery. Carbon
dioxide may also be injected into a sequestration well or may be
provided as a gaseous product to market. The carbon dioxide stream
may also be processed in a dehydration unit to lower the dewpoint
prior to sales. The carbon dioxide stream may further be passed
through an expander to recovery mechanical energy prior to venting
the stream.
[0065] While embodiments in this section have been discussed in
relation to a gas turbine system, it is also contemplated that the
above configurations are applicable to a hydrogen generation system
or other comparable system. For example, a fuel reforming reactor
may be substituted for the combustor above and the inputs thereto
may be methane and steam, which act as a fuel and oxidant,
respectively. When methane and steam are combusted in the fuel
reforming reactor, H.sub.2 and CO.sub.2 are produced as products in
the exhaust gas. The exhaust gas created as a result of the
hydrogen generation process may then be passed to the catalyst beds
308, where the CO.sub.2 is adsorbed as discussed above. In addition
to sequestering CO.sub.2 in the adsorbent bed, a stream of
concentrated H.sub.2 may be produced as H.sub.2 is not adsorbed by
the exemplary catalyst materials discussed herein. This
concentrated H.sub.2 may then be captured and used in numerous
applications.
Catalyst Materials
[0066] Preferably, the materials used in the catalyst beds 308
enable a reaction which consumes CO in the exhaust gas and produces
CO.sub.2. The catalyst beds also preferably have suitable
adsorption properties to adsorb the CO.sub.2 once it is
produced.
[0067] One example of a material suitable for the catalyst beds
includes a mixed metal oxide adsorbent, such as an adsorbent
including a mixture of an alkali metal carbonate and an alkaline
earth metal oxide and/or a transition metal oxide. Examples of
suitable alkali metal carbonates can include, but are not limited
to, a carbonate of lithium, sodium, potassium, rubidium, cesium, or
a combination thereof, e.g., a carbonate of lithium, sodium,
potassium, or a combination thereof. Examples of suitable alkaline
earth metal oxides can include, but are not limited to, oxides of
magnesium, calcium, strontium, barium, or a combination thereof,
e.g., oxides of magnesium and/or calcium. Some examples of suitable
transition metal oxides can include, but are not limited to, oxides
of lanthanide series metals, such as lanthanum, and/or of
transition metals that can form oxides with the metal in a +2 or +3
oxidation state (such as yttrium, iron, zinc, nickel, vanadium,
zirconium, cobalt, or a combination thereof).
[0068] In some aspects, the carbonate can be selected independently
from the oxide in the mixed metal oxide. In such aspects, the
carbonate can include, consist essentially of, or be lithium
carbonate, sodium carbonate, potassium carbonate, rubidium
carbonate, and/or cesium carbonate (e.g., lithium carbonate, sodium
carbonate, and/or potassium carbonate; lithium carbonate and/or
potassium carbonate; lithium carbonate and/or sodium carbonate; or
sodium carbonate and/or potassium carbonate).
[0069] In aspects where the carbonate is selected independently
from the oxide, the oxide can be an alkaline earth oxide, a
transition metal oxide, a combination of two or more alkaline earth
oxides, a combination of two or more transition metal oxides, or a
combination of oxides including at least one alkaline earth oxide
and at least one transition metal oxide. In aspects where the
independently selected oxide includes one or more alkaline earth
oxides, a suitable alkaline earth oxide can include, consist
essentially of, or be magnesium oxide, calcium oxide, strontium
oxide, and/or barium oxide, e.g., including at least magnesium
oxide and/or calcium oxide.
[0070] In aspects where the independently selected oxide includes
one or more transition metal oxides, suitable transition metals can
include, consist essentially of, or be one or more transition
metals that can form oxides with the metal in a +2 or +3 oxidation
state (e.g., yttrium oxide, iron oxide, zinc oxide, nickel oxide,
vanadium oxide, cobalt oxide, zirconium oxide, lanthanum oxide,
other oxides of lanthanide metals, and/or a combination thereof).
One preferred option includes a transition metal oxide selected
from lanthanum oxide and/or zirconium oxide. Another option
includes a metal oxide selected from lanthanum oxide, yttrium
oxide, zirconium oxide, and/or zinc oxide. Yet another option
includes a metal oxide selected from nickel oxide, cobalt oxide,
and/or iron oxide. Mixtures within each of these options and/or
across options are also contemplated, such as mixtures of lanthanum
oxide with zinc oxide and/or vanadium oxide; mixtures of lanthanum
oxide with iron oxide, cobalt oxide, and/or nickel oxide; mixtures
of zirconium oxide with yttrium oxide, zinc oxide, and/or vanadium
oxide; and mixtures of zirconium oxide with iron oxide, cobalt
oxide, and/or nickel oxide.
[0071] In aspects where the independently selected oxide includes
one or more alkali metal oxides and one or more transition metal
oxides, suitable alkali metal oxides can include, consist
essentially of, or be magnesium oxide, calcium oxide, strontium
oxide, and/or barium oxide, while suitable transition metals can
include, consist essentially of, or be transition metals that can
form oxides with the metal in a +2 or +3 oxidation state, such as
yttrium oxide, iron oxide, zinc oxide, nickel oxide, vanadium
oxide, cobalt oxide, zirconium oxide, lanthanum oxide, and/or other
lanthanide oxides. Each of these alkali metal oxides and transition
metal oxides can be independently selected individually or in any
combination of multiple transition metal oxides. Examples of
mixtures can include, consist essentially of, or be a mixture of
oxides where at least one oxide is lanthanum oxide, zirconium
oxide, and/or magnesium oxide; a mixture of oxides where the
mixture includes at least two of lanthanum oxide, zirconium oxide,
and magnesium oxide; a mixture of oxides where one oxide is
magnesium oxide and/or calcium oxide; and/or a mixture of oxides
where at least one oxide is lanthanum oxide, yttrium oxide, and/or
zirconium oxide.
[0072] In some alternative aspects, a mixed metal oxide can include
an alkaline earth carbonate in combination with a transition metal
oxide. In such aspects, the alkaline earth carbonate can include,
consist essentially of, or be magnesium carbonate and/or calcium
carbonate. Additionally or alternately, the alkaline earth
carbonate can be present in a mixture with an alkali metal
carbonate. Examples of such carbonate mixtures can include, consist
essentially of, or be mixtures of lithium carbonate with magnesium
carbonate, lithium carbonate with calcium carbonate, potassium
carbonate with magnesium carbonate, potassium carbonate with
calcium carbonate, sodium carbonate with magnesium carbonate, and
sodium carbonate with calcium carbonate (e.g., lithium carbonate
with magnesium carbonate or potassium carbonate with magnesium
carbonate). In such aspects, suitable transition metals can
include, consist essentially of, or be transition metals that can
form oxides with the metal in a +2 or +3 oxidation state, such as
yttrium oxide, iron oxide, zinc oxide, nickel oxide, vanadium
oxide, cobalt oxide, zirconium oxide, lanthanum oxide, other
lanthanide oxides, and/or a combination thereof. Each of these
alkaline earth carbonates and transition metal oxides can be
independently selected individually or in any combination of
multiple alkaline earth carbonates and/or multiple transition metal
oxides. For the transition metal oxide, one preferred option can
include a transition metal oxide selected from lanthanum oxide or
zirconium oxide. Another option can include a metal oxide selected
from lanthanum oxide, yttrium oxide, zirconium oxide, and/or zinc
oxide. Yet another option can include a metal oxide selected from
nickel oxide, cobalt oxide, and/or iron oxide. Mixtures within each
of these options and/or across options are also contemplated, such
as mixtures of oxides where at least one oxide is lanthanum oxide
and/or zirconium oxide; mixtures of lanthanum oxide with zinc oxide
and/or vanadium oxide; mixtures of lanthanum oxide with iron oxide,
cobalt oxide, and/or nickel oxide; mixtures of zirconium oxide with
yttrium oxide, zinc oxide, and/or vanadium oxide; and/or mixtures
of zirconium oxide with iron oxide, cobalt oxide, and/or nickel
oxide.
[0073] Additional or alternative materials can include
hydrotalcites.
Energy Recovery and Recycle of Exhaust
[0074] FIG. 3 is a schematic of a gas turbine system that includes
an HRSG 302 on the exhaust stream 218 from the expander exhaust
section 208. The HRSG 302 may include any number of heat recovery
units, such as a steam superheating device, a steam raising device,
a feed water heating device, or an endothermic reaction device,
among others. Thus, any HRSG 302 referred to herein may be replaced
with any other type of heat recovery unit. The exhaust gas in the
exhaust stream 218 can include, but is not limited to, unburned
fuel, oxygen, carbon monoxide, carbon dioxide, hydrogen, nitrogen,
nitrogen oxides, argon, water, steam, or any combinations thereof.
The exhaust stream 218 can have a temperature ranging from about
430.degree. C. to about 725.degree. C. and a pressure of about 101
kPa to about 110 kPa.
[0075] In the embodiment shown in the schematic, the heat generated
by the combustion can be used to boil an inlet water stream 304 to
generate a steam stream 306 that may also be superheated. The steam
stream 306 may be used, for example, in a Rankine cycle to generate
mechanical power from a steam turbine, or to provide steam for
utilities, or both. The mechanical power from the steam turbine may
be used to generate electricity, operate compressors, and the like.
As noted herein, the gas turbine system 300 is not limited to a
HRSG 302, as any type of heat recovery unit (HRU) may be used. For
example, the heat may be recovered in a heat exchanger to provide
hot water or other heated fluids. Further, a Rankine cycle based on
an organic working fluid (ORC) may be used to recover heat energy
by converting it to mechanical energy.
[0076] In an embodiment, one or more catalyst beds 308 may be
located in the HRSG 302 and described herein. The catalyst beds 308
may be located within the HRSG 302 by the reaction temperature
desired for the catalyst. For example, a catalyst that operates at
a higher temperature, such as an oxidation catalyst, may be located
in the HRSG 302 at a point just after the exhaust stream 218 enters
the HRSG 302. Similarly, a catalyst that operates at a lower
temperature may be located at a later point in the HRSG 302, for
example, just before a product gas 310 leaves the HRSG 302.
[0077] The cooled exhaust stream or product gas 310 may then be
used for other purposes, such as to provide recycle gas for stream
214. Various other sensors may be added to the system to monitor
and control the catalytic reaction. For example, sensors 312 may be
placed in the product gas 310 to determine the efficacy of the
catalytic reactions. These sensors 312 may be used in addition to
the sensors 206 on the expander exhaust section 208 to determine
the reactants present, and to control the fuel and oxidant
levels.
Individual Control of Equivalence Ratio to Combustors
[0078] The gas turbine systems discussed above may be used to
control the combustion process in the combustors 110, either
individually, as a group, or both. A goal of the control may be to
balance the equivalence ratio of the fuel and oxygen. This may be
performed to minimize unburned or partially burned hydrocarbon,
represented by the CO concentration in an exhaust stream and to
minimize unconsumed oxygen in the exhaust stream. The equivalence
ratio is discussed further with respect to FIG. 4A.
[0079] FIGS. 4A and 4B are graphical depictions of a simulation
showing the equilibrium relationship between the mole fraction 402
of oxygen and carbon monoxide as the equivalence ratio (.phi.) 404
changes from 0.75 to 1.25 and from 0.999 to 1.001, respectively.
The highest efficiency may be achieved when the equivalence ratio
is about 1.0. The oxygen concentration as a function of the
equivalence ratio is shown as line 406 and the carbon monoxide
concentration as a function of the equivalence ration is shown as
line 408. The equivalence ratio (.phi.) 404 is equal to (mol %
fuel/mol % oxygen).sub.actual/(mol % fuel/mol %
oxygen).sub.stoichiometric. The mol % fuel is equal to
F.sub.fuel/(F.sub.oxygen+F.sub.fuel), where F.sub.fuel is equal to
the molar flow rate of fuel and F.sub.oxygen is equal to the molar
flow rate of oxygen.
[0080] The mol % oxygen is equal to
F.sub.oxygen/(F.sub.oxygen+F.sub.fuel), where F.sub.oxygen is equal
to the molar flow rate of oxygen and F.sub.fuel is equal to the
molar flow rate of fuel. The molar flow rate of the oxygen depends
on the proportion of oxygen to diluent in the oxidant mixture, and
may be calculated as F.sub.oxygen/(F.sub.oxygen+F.sub.diluent). As
used herein, the flow rate of the oxidant may be calculated as
F.sub.oxidant=(F.sub.oxygen+F.sub.diluent).
[0081] As the equivalence ratio (.phi.) 404 goes below 1 or above 1
the mole fraction or concentration of oxygen and carbon dioxide in
the exhaust gas changes. For example, as the equivalence ratio
(.phi.) 404 goes below 1 the mole fraction of oxygen rapidly
increases from about 1 ppm (i.e., an oxygen mole fraction of about
1.0.times.10.sup.-6) at an equivalence ratio (.phi.) 404 of about 1
to about 100 ppm (i.e., an oxygen mole fraction of about
1.times.10-4) at an equivalence ratio (.phi.) 404 of about 0.999.
Similarly, as the equivalence ratio (.phi.) 404 goes above 1 the
concentration of carbon monoxide rapidly increase from about 1 ppm
(i.e., carbon monoxide mole fraction of about 1.times.10.sup.-6) at
an equivalence ratio (.phi.) 404 of about 0. 9995 to greater than
about 100 ppm (i.e., a carbon monoxide mole fraction of about
1.times.10.sup.-4) at an equivalence ratio (.phi.) 404 of about
1.001.
[0082] Based, at least in part, on the data obtained from the
sensors, such as sensors 206, or 312, the amount of oxidant 116
and/or the amount of fuel 114 the combustors 110 can be adjusted to
produce an exhaust stream 218 having a desired composition. For
example, monitoring the oxygen and/or carbon monoxide concentration
in the exhaust gas in the expander exhaust section 208 or the
cooled exhaust stream 310 allows the adjustment of the amount of
oxidant 116 and fuel 114 introduced the combustors 110, either
individual or as an ensemble, to be controlled such that combustion
of the fuel 114 is carried out within a predetermined range of
equivalence ratios (.phi.) 404 in the gas turbine engine 102. This
can be used to produce an exhaust stream 218 having a combined
concentration of oxygen and carbon monoxide of less than about 3
mol %, less than about 2.5 mol %, less than about 2 mol %, less
than about 1.5 mol %, less than about 1 mol %, or less than about
0.5 mol %. Furthermore, the exhaust stream 218 may have less than
about 4,000 ppm, less than about 2,000 ppm, less than about 1,000
ppm, less than about 500 ppm, less than about 250 ppm, or less than
about 100 ppm combined oxygen and carbon monoxide. In some
embodiments, the fuel 114 and oxidant 116 are adjusted to form a
slightly rich mixture to enhance the formation of CO at the expense
of the 0 2, favoring the water gas shift reaction. In other
embodiments, a slightly lean mixture is formed, to enhance the
formation of O.sub.2 at the expense of CO and unburned
hydrocarbons, favoring an oxidation reaction.
[0083] However, as the exhaust will contain a much higher content
of water vapor, for example, at about 10,000 ppm or higher, than
any other reactive component, the water gas shift reaction may more
favorable.
[0084] A desired or predetermined range for the equivalence ratio
(.phi.) 404 in the combustors 110 can be calculated or entered to
carry out the combustion of the fuel 114 to produce a mixed exhaust
stream 418 containing a desired amount of oxygen and/or carbon
monoxide. For example, the equivalence ratio (.phi.) in the
combustors 110 can be maintained within a predetermined range of
from about 0.85 to about 1.15 to produce an exhaust stream 218
having a combined oxygen and carbon monoxide concentration ranging
from a low of about 0.5 mol %, about 0.8 mol %, or about 1 mol %,
to a high of about 1.5 mol %, about 1.8 mol %, about 2 mol %, or
about 2.2 mol %. In another example, the equivalence ratio (.phi.)
404 in the combustors 110 can be maintained within a range of about
0.85 to about 1.15 to produce an exhaust stream 218 having a
combined oxygen and carbon monoxide concentration of less than 2
mol %, less than about 1.9 mol %, less than about 1.7 mol %, less
than about 1.4 mol %, less than about 1.2 mol %, or less than about
1 mol %. In still another example, the equivalence ratio (.phi.)
404 in the combustors 110 can be maintained within a range of from
about 0.96 to about 1.04 to produce an exhaust stream 218 having a
combined oxygen and carbon monoxide concentration of less than
about 4,000 ppm, less than about 3,000 ppm, less than about 2,000
ppm, less than about 1,000 ppm, less than about 500 ppm, less than
about 250 ppm, or less than about 100 ppm.
[0085] It will be noted that in embodiments in which the combustors
110 are individually controlled, the combustors 110 do not have to
be at the same set-point, or even within the same range. In various
embodiment, different or biased set-points may be used for each of
the combustors 110 to account for differences in construction,
performance, or operation. This may avoid a situation in which
different operational characteristics of different combustors 110
cause the exhaust stream 218 to be contaminated with unacceptable
levels of oxygen or carbon monoxide. Also, it will be noted that a
combination of combustion efficiency less that 100% and equivalence
ratio differences among the individual combustors 110 may result in
both CO 408 and oxygen 406 levels greater than those shown in FIGS.
4A and 4B at a given global equivalence ratio 404.
[0086] Accordingly, in embodiments of the present techniques, two
methods for operating the gas turbine 102 are used. In a first
method, the entire set of combustors 110 is operated as a single
entity, for example, during startup and in response to global
set-point adjustments, such as speed or power changes. In a second
method, the individual combustors 110 may be separately biased, for
example, to compensate for differences in wear, manufacturing, and
the like.
[0087] One method for operating the entire set of combustors 110
can include initially, i.e., on start-up, introducing the fuel 114
and oxygen in the oxidant 116 at an equivalence ratio (.phi.) 404
greater than 1. For example, the equivalence ratio (.phi.) 404 at
startup may range from a low of about 1.0001, about 1.0005, about
1.001, about 1.05, or about 1.1, to a high of about 1.1, about 1.2,
about 1.3, about 1.4, or about 1.5. In another example, the
equivalence ratio (.phi.) 404 can range from about 1.0001 to about
1.1, from about 1.0005 to about 1.01, from about 1.0007 to about
1.005, or from about 1.01 to about 1.1. For global adjustments, the
concentration of oxygen and/or carbon monoxide in the exhaust
stream 218 can be determined or estimated via the sensors 206, 224,
or 312. The expanded exhaust gas in the exhaust stream 218 may
initially have a high concentration of carbon monoxide (e.g.,
greater than about 1,000 ppm or greater than about 10,000 ppm) and
a low concentration of oxygen (e.g., less than about 10 ppm or less
than about 1 ppm).
[0088] Another method for operating the entire set of combustors
110 can include initially, i.e., on start-up, introducing the fuel
114 and oxygen in the oxidant 116 at an equivalence ratio (.phi.)
404 of less than 1. For example, the equivalence ratio (.phi.) 404
at startup may range from a low of about 0.5, about 0.6, about 0.7,
about 0.8, or about 0.9 to a high of about 0.95, about 0.98, about
0.99, about 0.999. In another example, the equivalence ratio
(.phi.) 404 can range from about 0.9 to about 0.999 from about 0.95
to about 0.99, from about 0.96 to about 0.99, or from about 0.97 to
about 0.99. The expanded exhaust gas in the exhaust stream 218 may
initially have a high concentration of oxygen (e.g., greater than
about 1,000 ppm or greater than about 10,000 ppm) and a low
concentration of carbon monoxide (e.g., less than about 10 ppm or
even less than about 1 ppm).
[0089] For example, when the concentration of oxygen in the exhaust
gas increases from less than about 1 ppm to greater than about 100
ppm, about 1,000 ppm, about 1 mol %, about 2 mol %, about 3 mol %,
or about 4 mol %, an operator, the control system 212, or both can
be alerted that an equivalence ratio (.phi.) 404 of less than 1 has
been reached. In one or more embodiments, the amount of oxygen via
oxidant 116 and fuel 114 can be maintained constant or
substantially constant to provide a combustion process having an
equivalence ratio (.phi.) 404 of slightly less than 1, e.g., about
0.99. The amount of oxygen via oxidant 116 can be decreased and/or
the amount of fuel 114 can be increased and then maintained at a
constant or substantially constant amount to provide a combustion
process having an equivalence ratio (.phi.) 404 falling within a
predetermined range. For example, when the concentration of oxygen
in the exhaust stream 418 increases from less than about 1 ppm to
about 1,000 ppm, about 0.5 mol %, about 2 mol %, or about 4 mol %,
the amount of oxygen introduced via the oxidant 116 can be reduced
by an amount ranging from a low of about 0.01%, about 0.02%, about
0.03%, or about 0.04% to a high of about 1%, about 2%, about 3%, or
about 5% relative to the amount of oxygen introduced via the
oxidant 116 at the time the increase in oxygen in the exhaust gas
is initially detected. In another example, when the concentration
of oxygen in the exhaust stream 218 increases from less than about
1 ppm to about 1,000 ppm or more the amount of oxygen introduced
via the oxidant 116 can be reduced by about 0.01% to about 2%,
about 0.03% to about 1%, or about 0.05% to about 0.5% relative to
the amount of oxygen introduced via the oxidant 116 at the time the
increase in oxygen in the exhaust gas is detected. In still another
example, when the concentration of oxygen increases from less than
about 1 ppm to about 1,000 ppm or more the amount offue1114 can be
increased by an amount ranging from a low of about 0.01%, about
0.02%, about 0.03%, or about 0.04% to a high of about 1%, about 2%,
about 3%, or about 5% relative to the amount of fuel 114 introduced
at the time the increase in oxygen in the exhaust gas is initially
detected.
[0090] During operation of the gas turbine system 102, the
equivalence ratio (.phi.) 404 can be monitored via the sensors 206,
224, or 312 on a continuous basis, at periodic time intervals, at
random or non-periodic time intervals, when one or more changes to
the gas turbine system 102 occur that could alter or change the
equivalence ratio (.phi.) 404 of the exhaust stream 218, or any
combination thereof. For example, changes that could occur to the
gas turbine system 102 that could alter or change the equivalence
ratio (.phi.) 404 can include a change in the composition of the
fuel, a change in the composition of the oxidant, a degradation of
the catalyst, for example, due to carbon formation, or a
combination thereof. As such, the concentration of oxygen and/or
carbon monoxide, for example, can be monitored, and adjustments can
be made to the amount of oxidant 116 and/or fuel 114 to control the
amounts of oxygen and/or carbon monoxide in the exhaust stream 218,
the product gas 310, or both. In at least one embodiment, reducing
the equivalence ratio (.phi.) 404 can be carried out in incremental
steps, non-incremental steps, a continuous manner, or any
combination thereof. For example, the amount of oxidant 116 and/or
the fuel 114 can be adjusted such that the equivalence ratio
(.phi.) 404 changes by a fixed or substantially fixed amount per
adjustment to the oxidant 116 and/or fuel 114, e.g., by about
0.001, by about 0.01, or by about 0.05. In another example, the
amount of oxidant 116 and/or fuel 114 can be continuously altered
such that the equivalence ratio (.phi.) 404 continuously changes.
Preferably the amount of oxidant 116 and/or fuel 114 is altered and
combustion is carried out for a period of time sufficient to
produce an exhaust gas of substantially consistent composition, at
which time the amount of oxidant 116 and/or fuel 114 can be
adjusted to change the equivalence ratio (.phi.) 404 in an amount
ranging from a low of about 0.00001, about 0.0001, or about 0.0005
to a high of about 0.001, about 0.01, or about 0.05. After the
exhaust stream 218 achieves a substantially consistent
concentration of oxygen the oxidant 116 and/or fuel 114 can again
be adjusted such that the equivalence ratio (.phi.) 404 changes.
The amount of oxygen and/or carbon monoxide in the exhaust stream
418 can be monitored and the amount of oxidant 116 and/or fue1 114
can be repeatedly adjusted until the exhaust stream 218 has a
combined concentration of oxygen and carbon monoxide, for example,
of less than about 2 mol % or less than about 1.5 mol %, or less
than about 1 mol %.
[0091] The combustors 110 can be operated on a continuous basis
such that the exhaust stream 218 has a combined oxygen and carbon
monoxide concentration of less than 2 mol %, less than 1 mol %,
less than 0.5 mol %, or less than about 0.1 mol %. In another
example, the time during which combustion is carried out within the
combustors 110, the exhaust stream 418 can have a combined oxygen
and carbon monoxide concentration of less than 2 mol % or less than
about 1 mol % for about 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%,
90%, or about 95% of the time during which the gas turbine
engine102 is operated. In other words, for a majority of the time
that combustion is carried out within the combustors 110, the
exhaust stream 418 can have a combined oxygen and carbon monoxide
concentration of less than about 2 mol %, less than about 1 mol %,
less than about 0.5 mol %, or less than about 0.1 mol %.
[0092] Once the overall control of the gas turbine engine 102 is
set, the biasing needed for individual combustors 110 may be
determined. For example, an oxidant flow adjusting device 202 for
each individual combustor 110 can be adjusted by the control system
212 to maintain the measured value of the sensors 206, 224, or 312
at or near to a desired set-point. Several calculated values may be
determined from the measured values of each sensor 206 or 312.
These may include, for example, an average value that can be used
to make similar adjustments to all of the oxidant flow adjusting
devices 202 in then combustors 110.
[0093] In addition, various difference values, for example,
calculated based on differences of the measured values of two or
more sensors 206, 224, or 312, may be used to make biasing
adjustments to the oxidant flow adjusting devices 202 on one or
more of the combustors 110 to minimize differences between the
measured values of the sensors 206, 224, or 312. The control system
212 may also adjust the oxidant system 116 directly, such by
adjusting compressor inlet guide vanes (IGV) or a speed control to
change the oxidant flow rates, for example, to all of the
combustors 110 at once. Further, the control system 212 can make
similar adjustments to the fue1 114 to all combustors 110,
depending, for example, on the speed selected for the gas turbine
102. As for the oxidant, the fuel supply to each of the combustors
110 may be individually biased to control the equivalence ratio of
the bum. This is discussed further with respect to FIG. 6.
[0094] FIG. 5 is a block diagram of a method 500 for adjusting fuel
and oxidant levels to the combustors 110 based on readings from an
array of sensors 206, 224, and 312. Like numbered items are as
described in FIGS. 1, 2, and 3. It can be assumed that the gas
turbine engine 102 has been started before the method 500 begins,
and that all of the combustors 110 are using essentially the same
mixture or a previous operation point. The method 500 begins at
block 502, when a set-point for the oxidant 116 is entered and
oxidant is provided to the combustors 110. In a substantially
simultaneous manner, at block 504, a set-point is entered for the
fuel 114, and fuel 114 is provided to the combustors 110. At block
506, the combustion process consumes the fue1 114 and oxidant 116
provided.
[0095] At block 508, the exhaust gas is passed through one or more
catalyst beds, for example, including oxidation catalysts, water
gas shift catalysts, or both. At block 510, readings are obtained
from the sensors 206, 224, or 312. The readings may indicate the
efficacy of the catalyst processes, by determining the
concentrations of H.sub.2O, O.sub.2, CO.sub.2, H.sub.2, and other
gas components. These may be used to determine global adjustments
to the combustors. Further, individual sensors 206 along the
exhaust expander ring 208 may be used to determine sums and
differences of concentrations from individual combustors 110. The
sums and differences may be combined to assist in identifying the
combustors 110 that are contributing to a high oxygen or high
carbon monoxide condition in the exhaust. This may also be
performed by a swirl chart, as described above. Adjustments to the
fuel 114 and oxidant 116 for those combustors 110 may be calculated
and added to any global adjustments. Process flow then returns to
blocks 502 and 504 with the new set points, wherein the method 500
repeats.
Control System
[0096] FIG. 6 is a block diagram of a plant control system 600 that
may be used to control the oxidant 116 and fuel 114 to the
combustors 110 in a gas turbine engine 102. As previously
mentioned, the control system 600 may be a DCS, a PLC, a DDC, or
any other appropriate control device. Further, any controllers,
controlled devices, or monitored systems, including sensors,
valves, actuators, and other controls, may be part of a real-time
distributed control network, such as a FIELDBUS system, in
accordance with IEC 61158. The plant control system 600 may host
the control system 212 used to adjust the fue1 114 and oxidant 116
to the combustors 110, individually or as an ensemble.
[0097] The control system 600 may have a processor 602, which may
be a single core processor, a multiple core processor, or a series
of individual processors located in systems through the plant
control system 600. The processor 602 can communicate with other
systems, including distributed processors, in the plant control
system 600 over a bus 604. The bus 604 may be an Ethernet bus, a
FIELD BUS, or any number of other buses, including a proprietary
bus from a control system vendor. A storage system 606 may be
coupled to the bus 604, and may include any combination of
non-transitory computer readable media, such as hard drives,
optical drives, random access memory (RAM) drives, and memory,
including RAM and read only memory (ROM). The storage system 606
may store code used to provide operating systems 608 for the plant,
as well as code to implement turbine control systems 610, for
example, bases on the first or second methods discussed above.
[0098] A human-machine interface 612 may provide operator access to
the plant control system 600, for example, through displays 614,
keyboards 616, and pointing devices 618 located at one or more
control stations. A network interface 620 may provide access to a
network 622, such as a local area network or wide area network for
a corporation.
[0099] A plant interface 624 may provide measurement and control
systems for a first gas turbine system. For example, the plant
interface 624 may read a number of sensors 626, such as the sensors
206, 224, and 312 described with respect to FIGS. 2 and 3. The
plant interface 624 may also make adjustments to a number of
controls, including, for example, fuel flow controls 628 used
adjust the fuel 114 to the combustors 110 on the gas turbine 102.
Other controls include the oxidant flow controls 630, used, for
example, to adjust the actuator 404 on an oxidant flow adjusting
device 402, the actuator 706 on a oxidant flow adjusting valve 702,
or both, for each of the combustors 110 on the gas turbine 102. The
plant interface 624 may also control other plant systems 632, such
as generators used to produce power from the mechanical energy
provided by the gas turbine 102. The additional plant systems 632
may also include the compressor systems used to provide oxidant 116
to the gas turbine 102.
[0100] The plant control system 600 is not limited to a single
plant interface 624. If more turbines are added, additional plant
interfaces 634 may be added to control those turbines. Further, the
distribution of functionality is not limited to that shown in FIG.
6. Different arrangements could be used, for example, one plant
interface system could operate several turbines, while another
plant interface system could operate compressor systems, and yet
another plant interface could operate generation systems.
* * * * *