Note: Descriptions are shown in the official language in which they were submitted.
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VORTEX COMBUSTOR FOR LOW NOX EMISSIONS
WHEN BURNING LEAN PREMIXED HIGH HYDROGEN CONTENT FUEL
TECHNICAL FIELD
This invention relates to burners and combustors, including high efficiency
combustors for gas turbine engines, as well as to process applications for gas
turbine engines utilizing such combustors.
BACKGROUND
The development of novel or improved processes for combustion of high
hydrogen content fuels has become increasingly important in view of the
development of various integrated power generation and fuel synthesis
processes, especially where such processes produce fuels with significant
hydrogen content. Commercially available gas turbines have typically been
developed for the combustion of natural gas, i.e., a methane-rich fuel with
high
calorific values in the range of from about 29.807 MJ/m3 to about 44.711 MJ/m3
(about 800 to about 1200 British Thermal Units per standard cubic foot),
wherein
standard conditions are 101.56 KPa (14.73 pounds per square inch) absolute
and 15.56 C (60 F). While such gas turbines have been adapted to burn certain
syngas fuels, and more specifically fuels with low calorific value often in
the
range of from about 3.726 MJ/m3 to about 11.178 MJ/m3 (about 100 to about
300 BTU/scf), gas turbine combustor design features have not generally been
optimized for hydrogen content or low grade gaseous fuel applications.
Conventional gas turbine engines encounter two basic difficulties when
transitioning from natural gas to syngas. First, for the same fuel heat input,
the
mass flow of a syngas fuel is often four to five times greater than that for
natural
gas, due to the lower heating value of the syngas fuel. Second, although
premixed natural gas and air combustion systems have become common place
for controlling NOx emissions, such systems have not been successfully
implemented for syngas applications, due to the high hydrogen content of the
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syngas, and the accompanying potential for flashback of the flame into the
fuel
injection system. Consequently, diffusion flame or "non-premixed" combustors
which have been used in the combustion of syngas have been configured to
control the NOx emissions by diluting the syngas with nitrogen, steam or
carbon
dioxide. In such designs, the diluent reduces the flame temperature and
consequently reduces the formation of NOx.
In the combustion of natural gas, dry (i.e., no addition of steam or water)
low NOx (DLN, or "Dry Low NOx") combustors can achieve less than 10 ppmvd
(10 parts per million by volume, dry, at 15% Oxygen) NOx emissions with a
natural gas fuel. Such DLN combustors rely on the premix principle, which
reduces the combustion flame temperature, and consequently the NOx
emissions. DLN combustors are able to achieve much lower NOx emissions
than diluted non-premixed combustors because of higher premixing time prior to
the combustion zone.
In high hydrogen content fuel, such as is found in some syngas mixtures
(up to 60% hydrogen by volume or more), or in pure hydrogen fuel sources, the
flame speeds may be up to as much as six times faster than the flame speed
that
is typical in combustion of natural gas. Consequently, such high flame speed
mixtures, whether from syngas based fuels or from other hydrogen source fuels,
makes the use of a DLN combustion system impossible, because in such a
system the flame would flash back into the premix zone, and destroy the fuel
injection hardware.
On the other hand, the diluted non-premixed combustors have a chemical
kinetic limit when too much diluent is added for reduction of NOx emissions.
The
increase in diluent causes flame instability in the combustion zone, and
eventually, combustor flame-out. Consequently, in the best case, a practical
NOx reduction limit for prior art syngas combustors is presently between about
10 and about 20 ppmvd NOx.
In summary, there remains an as yet unmet need for a combustor for a
gas turbine engine that may be utilized for the combustion of high hydrogen
content fuels. In order to meet such needs and achieve such goals, it is
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necessary to address the basic technical challenges by developing new system
designs. As described herein, advantageous gas turbine system designs may
include the use of a lean premix with high hydrogen content fuels in
combination
with the use of trapped vortex combustors.
BRIEF DESCRIPTION OF THE DRAWING
The present invention will be described by way of exemplary
embodiments, illustrated in the accompanying drawing in which like reference
numerals denote like elements, and in which:
FIG. 1 provides a plan view of a novel trapped vortex combustor,
illustrating the pre-mixing of fuel such as a hydrogen rich fuel and oxidant,
as well
as the use of laterally extending mixing struts that enable combustion gases
from
the trapped vortex to mix with the incoming fuel-air premix.
FIG. 2 provides an elevation view of an embodiment of a novel trapped
vortex combustor configuration, taken along section 2-2 of FIG. 1, more
clearly
showing a first bluff body and a second or aft bluff body, which enables the
setup
of a stable vortex between the first and second bluff bodies for the
combustion of
a lean premixed fuel and oxidant mixture, as well as the use of laterally
extending
struts to promote mixing of the entering premix with hot gases that are
escaping
from a stable vortex between the first bluff body and a second bluff body.
FIG. 3 provides a perspective view of an embodiment of a novel trapped
vortex combustor, showing a circulating main vortex similar to that first
illustrated
in FIG. 1, now showing the use of multiple laterally extending mixing devices,
here depicted in the form of partially airfoil shaped outwardly or laterally
extending mixing devices extending into the bulk lean premixed fuel and
oxidant
flow adjacent the dump plane of the combustor.
FIG. 4 provides a process flow diagram for a prior art Integrated
Gasification Combined Cycle ("IGCC") process, showing the use of a diffusion
combustor in a gas turbine, and the feed of compressed air from both the gas
turbine compressor and from the motor driven compressor to an air separation
unit for the production of oxygen and nitrogen, as well as the use of a
selective
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catalytic reduction hot gas emissions cleanup process subsequent to the gas
turbine.
FIG. 5 provides a process flow diagram for an Integrated Gasification
Combined Cycle ("IGCC") process similar to that first described in FIG. 4
above,
but compared to the process shown in FIG. 4, now eliminates the use of diluent
gas feed to the combustor, and the use of SCR emissions cleanup technology,
both of which process steps may be eliminated from an IGCC plant via use of
the
novel trapped vortex combustor described and taught herein.
FIG. 6 provides a process flow diagram for a novel Integrated Gasification
Combined Cycle ("IGCC") plant, showing the use of a novel trapped vortex
combustor in a gas turbine, and also showing the elimination of use of
selective
catalytic reduction or similar process after the combustion of syngas in the
gas
turbine for NOx reduction, as well as the elimination of the use of nitrogen
diluent
to control NOx emissions from the gas turbine engine.
The foregoing figures, being merely exemplary, contain various elements
that may be present or omitted from actual embodiments which may be
implemented, depending upon the circumstances. An attempt has been made to
draw the figures in a way that illustrates at least those elements that are
significant for an understanding of the various embodiments and aspects of the
invention. However, various other elements of a novel trapped vortex
combustor,
and methods for employing the same in the combustion of high flame speed fuels
such as hydrogen rich syngas, may be utilized in order to provide a versatile
gas
turbine engine with novel trapped vortex combustor for combustion of a fuel-
air
premix while minimizing emissions of carbon monoxide and oxides of nitrogen.
30
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DETAILED DESCRIPTION
As depicted in FIG. 1, a novel trapped vortex combustor 10 design has
been developed for operation in a low NOx, lean premixed mode on hydrogen-
rich fuels, yet accommodates the high flame speed that is a characteristic of
such
fuels. In some embodiments, such a combustor 10 can achieve extremely low
NOx emissions without the added capital and operating expense of post-
combustion treatment of the exhaust gas. Further, such a combustor 10 can
eliminate the costly requirement for high pressure diluent gas (nitrogen,
steam or
carbon dioxide) for NOx emissions control.
As easily seen in FIG. 1, in the novel trapped vortex combustor 10 design
disclosed herein, at least one cavity 12 is provided, having a selected size
and
shape to stabilize the combustion flame for a selected fuel composition. Flame
stabilization is accomplished by locating a fore body, hereinafter identified
as first
bluff body 14, upstream of a second, usually smaller bluff body - commonly
referred to as an aft body 16. Fuel F, such as a hydrogen rich syngas, is
provided by fuel outlets 18, and the fuel F is mixed with incoming compressed
oxidant containing stream A, which oxidant containing stream A may be a
compressed air stream containing both oxygen and nitrogen (or in other
embodiments, another inert working fluid, such as steam or carbon dioxide).
The
in-flow of bulk fluid continues in the direction of fluid flow reference
numeral 20,
ultimately providing a lean fuel-air premixed stream 22 for entry to the
combustion zone that occurs at or adjacent cavity 12. Fluid flow issuing from
around the first bluff body 14 separates, but instead of developing shear
layer
instabilities (that in most circumstances becomes the prime mechanism for
initiating flame blowout), an alternating array of vortices 24 and 26 are
conveniently trapped or locked between the first 14 and second 16 bluff
bodies.
In some embodiments of the novel trapped vortex combustor 10 design
disclosed herein, the re-circulation of hot products of combustion into the
incoming, lean premixed fuel and oxidant mixture stream 22 may be
accomplished by incorporating various features. In one embodiment, a stable
recirculation zone may be generated in on or more vortices, such as vortices
24
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and 26, located adjacent to the main fuel-air flow. When the fluid flow in the
vortex or cavity 12 region is designed properly, the flow of the swirling
combustion gases comprise one or more vortices that are stable, at least with
respect to the one or more primary trapped vortices, and vortex shedding is
substantially avoided. Each of the one or more stable primary vortices are
thus
used as a source of heat, or more precisely, a source of hot products of
combustion. Further, heat from the vortex or cavity 12 region must be
transported into the main entering lean premix fuel and oxidant mixture
stream,
and mixed into the main flow. As shown in FIG. 1, in one embodiment, this may
be done in part by escape of a portion of combustion gases from the vortices
24
and 26 in cavity 12 outward in the direction of the incoming lean premixed
fuel
and oxidant stream flow 22. In one embodiment, such mixing may be
accomplished by using structures to create a flow of combustion gases having a
substantial transverse component. In this way, structures such as struts 30
create stagnation zones, from which mixing occurs, such as via wakes 32 or 34,
for example, as seen in FIG. 1. In such embodiments, the incoming lean
premixed fuel and oxidant mixture 22 is at least in part, if not primarily,
ignited by
lateral mixing, instead of solely by a back-mixing process. In some
embodiments, at least one pair of struts 30 may be provided. Similarly, at
least
one of the at least one pair of struts 30 may include a rear planar portion
31, as
can be appreciated from FIG. 2. From FIGS. 1 and 2, it can be seen that in
some embodiments, the planar rear portion 31 may be oriented coplanar with the
rear wall 44 of the first bluff body 14. Further one or more of the struts 30
may
include an upstream portion 33 shaped for low aerodynamic drag.
In any event, by providing suitable geometric features such as struts 30,
there is provided in the trapped vortex combustor 10 at least some lateral or
transverse flow of hot gases, to provide lateral mixing to ignite the incoming
fuel-
air mixture. By using such structures as struts 30 in a mixing technique, the
novel trapped vortex combustor 10 design disclosed herein is believed less
sensitive to flame instabilities and other process upsets. This is
particularly
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important when operating near the lean flame extinction limit, where small
perturbations in the fluid flow can lead to flame extinction.
Thus, in the novel trapped vortex combustor design disclosed herein, the
very stable yet highly energetic primary/core flame zone is very resistant to
external flow field perturbations, and therefore yields extended lean and rich
blowout limits relative to a dump combustor having a simple bluff body
component. The unique characteristic of the presently described novel trapped
vortex combustor technology provides a fluid dynamic mechanism that can
overcome the high flame speed of a hydrogen-rich gas, and thus has the
capability to allow combustors to operate with a hydrogen rich gaseous feed
stream with a lean fuel-air premix composition.
In one embodiment, the novel trapped vortex combustor design
configuration described herein also has a large flame holding surface area,
and
hence can facilitate the use of a compact primary/core flame zone, which is
essential to promoting high combustion efficiency and reduced CO emissions.
As noted in FIGS. 2 and 3, in one embodiment, the trapped vortex
combustor 10 includes a base 40. The first bluff body 14 extends outward from
the base 40 for a height or distance of Y1, and the second bluff body 16
extends
outward from the base for a height or distance of Y2. In one embodiment, Yj is
equal to Y2, and the combustor 10 also includes a ceiling 42, so that during
operation, a stabilized vortex of mixing and burning gas 12 is trapped between
the rear wall 44 of the first bluff body 16 and the front wall 46 of the
second bluff
body 16, and between base 40 and ceiling 42.
In one embodiment, as noted in FIG. 3, between the rear wall 44 of the
first bluff body 14 and the front wall 46 of the second bluff body 16, at
least a
portion of the gas from each stabilized vortex 24 and 26 of mixing and burning
gas moves in the bulk fluid flow direction, i.e., the same direction as the
premixed
fuel and oxidant mixture stream flow 22 shown in FIG. 1. Also, in one
embodiment, as noted in FIG. 3, between the rear wall 44 of the first bluff
body
14 and the front wall 46 of the second bluff body 16, at least a portion of
each
stabilized vortex of mixing and burning gas 24 and 26 moves in a direction
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opposite the bulk fluid flow direction, i.e., opposite the direction as the
premixed
fuel and oxidant mixture inflow 22 shown in FIG. 1.
As better seen in FIGS. 1 and 2, in one embodiment, the novel trapped
vortex combustor 10 further comprises one or more outwardly extending
structures such as struts 30. In some embodiments, struts 30 may include a
planar rear portion 31. In some embodiments, the rear planar portion 31 may be
substantially co-planar with the rear wall 44 of the first bluff body 14. As
seen in
FIG. 3, in some embodiments, one or more struts 30 may be provided. In some
embodiments, multiple struts 30 may be provided in a configuration where they
extend outwardly from adjacent the rear wall 44 of the first bluff body 14. In
some embodiments, the struts 30 may extend transversely with respect to
longitudinal axis 50, or may include at least some transverse component, so
that
circulation of a portion of escaping heat and burning gases flow adjacent
struts
30 and are thus mixed with an incoming lean premixed fuel and oxidant mixture.
As generally shown in FIGS. 1 through 3, and specifically referenced in
FIG. 3, a novel trapped vortex combustor 10 can be provided wherein the
combustor 10 has a central longitudinal axis 50 see FIG. 1) defining an axial
direction. For reference, a combustor may include, extending along the
longitudinal axis 50, a distance outward toward the ceiling 42 along an
outward
direction 52, or alternately in an inward, base direction 54 both oriented
orthogonal to the axial direction. Also for reference, a trapped vortex
combustor
10 may include, space extending in a transverse direction 56 or 58, oriented
laterally to the axial direction 50. A pressurizable plenum 60 is provided
having a
base 40, an outer wall or ceiling 42, and in some embodiments, combustor first
and second sidewalls 64 and 66, respectively.
In some embodiments, the first bluff body 14 includes a nose 70 and
opposing first 74 and second 76 bluff body sidewalls, as well as rear 44 noted
above. The second bluff body 16 is located downstream from the first bluff
body
16. The second bluff body has an upstream side having a front wall 46, a
downstream side having a back wall 78, and first 80 and second 82 opposing
sidewalls.
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As seen in FIGS. 1 and 2, a mixing zone 84 is provided downstream of the
gaseous fuel inlets 18. The mixing zone 84 is upstream of the rear wall 44 of
the
first bluff body 14. The mixing zone 84 has a length LMZ along the axial
direction
50 sufficient to allow mixing of fuel and oxidant, and particularly gaseous
fuel and
gaseous oxidant, to form a lean premixed fuel and oxidant stream 22 having an
excess of oxidant. The pressurizable plenum 60, first bluff body 14, and
second
bluff body 16 are size and shaped to receive the lean premixed fuel and
oxidant
mixture stream 22 at a velocity greater than the combustion flame speed in the
lean premixed fuel and oxidant mixture 22 composition. Once the cavity 12 is
reached, flow wise, a primary combustion zone of length LPZ is provided,
wherein
one or more stabilized vortices 26 and 26 are provided to enhance combustion
of
the entering fuel. After the aft bluff body 16, combustion burnout zone of
length
LBZ is provided, of sufficient length so that final hot combustion exhaust
gases,
described below, meet the desired composition, especially with respect to
minimizing the presence of carbon monoxide.
As seen in FIGS. 1 and 3, in some embodiments, the second bluff body 16
is further configured to provide one or more vortex stabilization jets 90.
Each of
the one or more vortex stabilization jets 90 provides an upstream jet of gas
in a
direction tending to stabilize vortex 22 and vortex 24 in the cavity 12
between the
first bluff body 14 and the second bluff body 16. In one embodiment, the
second
bluff body 16 is coupled to a source of fuel, and in such a case, at least one
of
the vortex stabilization jets provides an injection stream containing a fuel.
In such
an embodiment, the second bluff body 16 may be coupled to a source of syngas,
and in such a case, the fuel comprises a syngas. In yet other embodiments, the
second bluff body 16 is coupled to a source of oxidant, and in such cases, one
or
more of the at least one vortex stabilization jets 90 has an injection jet
stream
containing an oxidant. In yet another embodiment, the vortex stabilization
jets
may include a first jet 90 containing a fuel, and a second jet 92 containing
an
oxidant. In a yet further embodiment, the vortex stabilization jets may be
used in
a process where the second bluff body 16 is coupled to a source of lean
premixed fuel and oxidant, and wherein a stream comprising lean premixed fuel
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and oxidant is injected through at least one of the one or more vortex
stabilization
jets 90.
In any event, the novel trapped vortex combustor 10 includes first 14 and
second 16 bluff bodies that are spaced apart in a manner that when the trapped
vortex combustor 10 is in operation, the heat and combustion products produced
during combustion of the lean premix are continuously recirculated in a
recirculation zone in the cavity 12 between the first 14 and second 16 bluff
bodies, and wherein heat and combustion products exit longitudinally
(reference
direction 50) and laterally (which may include transversely such as in
reference
directions 56 and 58) from the cavity 12 and are employed to continuously
ignite
a lean premixed fuel and oxidant mixture entering the tapped vortex combustor
10. In some embodiments, the lean premixed fuel an oxidant mixture enters
adjacent cavity 12, from flow along side of walls 74 and 76 of first bluff
body 14.
High hydrogen content fuels present a particular problem in that the flame
speed during the combustion of a premixed stream of pure hydrogen gas and air
is approximately six times (6x) that of the flame speed of a premixed stream
of
natural gas and air. Thus, in order to prevent flashback of a flame upstream
from
a combustor when burning premixed fuels containing hydrogen, the thru-flow
velocity needs to be greater, and in some embodiments (depending upon the
hydrogen content in the fuel mixture) significantly greater than the flame
speed.
Such problems are compounded in lean pre-mix combustor designs since
flashback of the flame into the fuel injector may cause severe damage to the
hardware, and has the clear potential, for example, to lead to gas turbine
failure.
As a result of such factors, in so far as we are aware, presently there are no
lean
pre-mix gas turbines in operation in industry on high hydrogen content fuels.
In our method of construction and operation of a suitable novel trapped
vortex combustor 10, the bulk fluid velocity 20 entering the combustion zone
adjacent trapped vortex 12 exceeds the flame speed of combustion occurring in
the lean premix composition. In some embodiments, the bulk fluid velocity
entering the novel trapped vortex combustor 10 exceeds the flame speed of
combustion occurring in the lean premix by a factor of from about 3 to about 6
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thereabouts. Depending upon the actual gaseous composition, fuels containing
significant amounts of hydrogen will have turbulent flame speeds from about
thirty five (35) meters per second to about fifty (50) meters per second
(about
114.83 ft/sec to about 164.04 ft/sec). Thus, in order to achieve desirable
safety
margins necessary when operating on hydrogen rich gaseous fuel, the bulk
velocity 20 of lean premix may be provided at about one hundred five (105)
meters per second (344.48 ft/sec), and up to as much as about one hundred
fifty
(150) meters per second (492.12 ft/sec), or more. Such bulk pre-mixed fuel
velocities allow protection against flash back even when operating on high
hydrogen content fuels, and thus are a significant improvement when applied as
combustors in gas turbines.
In short, the novel trapped vortex combustor 10 described and claimed
herein can provide a significant benefit in gas turbine designs for high
hydrogen
content fuels. Such fuels may be found in the syngas from coal gasification
technology applications, such as Integrated Gasification Clean Coal ("IGCC")
plants, or in Combined Cycle Gasification Technology ("CCGT") plants. Also, in
some embodiments, the novel trapped vortex combustor 10 described and
claimed herein may provide a significant benefit in the design and operation
of
equipment for the combustion of hydrogen rich streams in other systems.
As shown in FIG. 4, in a prior art clean coal process plant 118, oxygen-
blown coal gasifiers 120 are utilized to generate a synthesis gas 122 that is
rich
in hydrogen and in carbon monoxide. Such synthesis gas 122 is typically
cleaned in a gas cleanup unit 124, and the clean synthesis gas 126 is used as
a
fuel in a gas turbine 128. The synthesis gas 126 is typically burned in a
diffusion
combustor 130. The production of raw synthesis gas 122 thus requires an
oxygen source, which is typically provided by way of a cryogenic air
separation
unit ("ASU") 131. Alternately, the oxygen source may be a high temperature ion
transport membrane (not shown). As is illustrated in FIG. 4, in typical prior
art
process design, a portion 132 of the air 134 for the ASU 131 is provided by
the
compressor 133 of the gas turbine 128, and a portion 136 of the air 134 for
the
ASU 131 is provided by a separate motor 140 driven feed air compressor 142.
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The respective contribution of the gas turbine compressor 133 and the
supplemental feed air compressor 142 is commonly referred to as the "degree of
integration". The "degree of integration" varies with the specific plant
designs,
but the norm is approximately fifty percent (50%) integration, where half of
the
ASU 131 feed air 134 comes from the gas turbine compressor 133, and half of
the ASU 131 feed air 134 comes from separate motor 140 drive (typically
electric
drive) feed air compressor(s) 142.
The heating value of typical cleaned synthesis gas ("syngas") 126 from an
IGCC plant is normally below 9.315 MJ/m3 (250 British Thermal Units per
standard cubic foot) which is approximately one-fourth (1/4) of the heating
value of
a typical natural gas supply. Stated another way, four (4) times the gaseous
volume of clean syngas 126 fuel is required to be fed to a gas turbine 128 in
order to generate the same power output that would be generated if the gas
turbine 128 were, instead, fueled utilizing a typical natural gas supply.
Unfortunately, conventional swirl-stabilized lean pre-mix combustor
designs cannot be used with a hydrogen-rich syngas 126 fuel because of
concerns over the possibility of flame flashback in a hydrogen rich fuel, and
over
the possibility of auto-ignition in a high pressure pre-mix fuel/oxidant
stream.
Gas turbine manufacturers offer various conventional, non-pre-mix diffusion
combustor 130 designs that have marginal emissions signatures. In such
conventional prior art diffusion combustor 130 designs, nitrogen 144 is added
as
a diluent, in order to reach a desired NOx emissions level, such as a 25 ppm
NOx emission level. In other, non-IGCC gas turbine applications, various other
diluent gases such as C02 (carbon dioxide) and H2O (steam) can also used for
NOx control, but with the same adverse, efficiency decreasing results. Note
that
in the typical IGCC plant 118 as conceptually depicted in FIG. 4, although
nitrogen 144 diluent comes from the ASU 131 as a by-product of the air
separation process, there may need to be, at extra capital cost and at extra
operating expense, an additional diluent gas compressor (not shown).
For further treatment of the products of combustion to reduce oxides of
nitrogen, a selective catalytic reduction ("SCR") system 150 may be used to
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reach a 3 ppm NOx emission value requirement, as is often established by
regulation of applicable governmental authorities. In certain SCR systems 150,
optimum reaction temperature for the SCR process may be provided by linking
the SCR system 150 with the heat recovery steam generator ("HRSG") 152. The
HRSG 152 may be utilized for recovery of heat and generation of steam 154 for
use in a steam turbine 156 for shaft power, such as via shaft 156s to an
electric
generator 157 (similar to configuration illustrated in FIG. 6) or for process
use
(not shown). In any event, condensed steam is collected at a condenser 158 and
returned as condensate to the HRSG 152. Also, electrical power is generated
via shaft 128s power from gas turbine 128 that is used to turn generator 159.
Where utilized, the above mentioned electrical generator 157 is driven by
steam
turbine 156.
In such prior art IGCC plants 118, the total combined gaseous products of
combustion flow stream 160, from the added syngas fuel flow volume (up to four
times or more by volume, compared to natural gas), and from the added nitrogen
144 diluent flow volume, creates a mass flow mismatch (and thus load mismatch)
between the compressor section 133 and the turbine section 162 of a gas
turbine
128 designed for use on a typical natural gas fuel. A higher mass flow rate
through the turbine section 162 may increase the pressure at the compressor
section 133 outlet too much, so that the compressor approaches, or if left
unaddressed would encroach, a compressor surge region, where such total
mass flow would no longer be sustainable. In various plant designs, such a
mismatch is "managed" by adjusting the degree of integration, which usually
means removal of at least a portion of the compressed air mass flow 132 to the
ASU 131 from the gas turbine compressor 133. Alternately, a gas turbine
manufacturer could add a compressor stage to allow higher overall pressure
ratio
in the compression cycle. Further, the high mass flow of syngas as compared to
natural gas might approach the mechanical limits of a gas turbine rotor to
handle
turbine power output. Thus, while close coupling of the ASU 131 and the gas
turbine 128 in an IGCC plant would seem to be synergistic, in prior art plant
designs, there remain various workaround issues in plant design with respect
to
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efficient combustion of syngas 126, such designs are subject to various
capital
cost penalties and/or system efficiency losses, whether from costs of the SCR
system for NOx cleanup, or for load matching with respect to compressed air
requirements, or from nitrogen 144 dilution practice.
By comparison of FIGS. 4 and 5, it is particularly pointed out that the use
of a novel trapped combustor 10 as described and claimed herein to produce a
hot combustion exhaust gas stream 164 would allow the provision of an IGCC
plant that eliminates the practice of use of nitrogen 144 dilution in burners,
and
that eliminates the use of an SCR system, whether in a high temperature
embodiment for direct receipt of combustion gases from gas turbine 162' (not
illustrated), or the use of an SCR system 150 (as shown in a low temperature
embodiment in conjunction with the HRSG 152 as noted in FIG. 4).
As can be appreciated from FIG. 5, uncoupling of the gas turbine 128'
compressor 133' with requirement for supply of the ASU 131 also offers the
potential for savings in some fuel synthesis plants, by freeing up the
compressor
133' so that the parasitic air compression load is reduced. Many of the gas
turbine compressors currently available operate most efficiently at a pressure
ratio of about twenty (20), which means that when compressing atmospheric air,
there is about a 2068.43 KPa (three hundred (300) pounds per square inch)
absolute discharge pressure. However, since most ASU units 131 presently
operate in the 1034.21 KPa (one hundred fifty (150) pounds per square inch)
gauge range, excess compression work may sometimes take place in
preparation of compressed air feed 134 for the ASU 131. However, if in the
plant
170 design shown in FIG. 5, valve 172 is closed and all of the feed air 134 to
the
ASU 131 is provided using a 4-stage intercooled motor 140' driven compressor
142' operating at 1945.70 KPa (282.2 psia) discharge pressure, the total air
compression costs would be less than the costs associated with the case shown
in FIG. 4 where valve 172 is open and 50% of supply for the air separation
unit
131 is provided via the gas turbine compressor 133 bleed air supply. Further,
if
all of the ASU 131 feed air were provided by a motor 140" driven intercooled
multistage compressor 142" operating only at 1135.57 KPa (one hundred sixty
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four point seven (164.7) psia) discharge pressure, then there would be a
significant energy savings for the supply of compressed air to the ASU.
Moreover, the gas turbine compressor 133' could in such a case be designed to
solely handle the oxidant supply requirements to combustor 10 (or to handle
compression of an oxidant and an inert working gas such as carbon dioxide or
steam where such fluids are used to increase work output from turbine 162' of
the gas turbine engine 128'), without regard to any integration requirements
with
the ASU air supply.
In any event, a novel trapped vortex combustor 10 can be adapted for
use in, or in combination with, various types of gas turbines for the
combustion
of high hydrogen content fuels, especially such fuels from various types of
fuel
synthesis plants, such as carbonaceous matter gasification plants, including
coal
or coke gasification plants. In one embodiment, this may be made possible by
decreasing the mass flow through the turbine section. Also, in one embodiment,
a novel trapped vortex combustor 10 design can improve the overall cycle
efficiency of a gas turbine, by decreasing the pressure drop through the
trapped
vortex combustor 10, as compared with a prior art diffusion combustor 30. And,
such a novel trapped vortex combustor 10 design can extend the lean blowout
limit while offering greater turndown, (i.e. load following capability), with
improved
combustion and process stability. In summary, a novel trapped vortex combustor
10 design holds tremendous promise for combustion of hydrogen rich fuels in
various gas turbine 128' applications. Such a design offers improved
efficiency,
lower emissions levels, greater flame stability, increased durability, added
fuel
flexibility, and reduced capital costs, compared to prior art designs.
The novel trapped vortex combustor 10 described and claimed herein may
be utilized in a variety of gaseous fuel synthesis plants that make hydrogen
rich
fuels. One such plant is an integrated gasification process, as conceptually
depicted in FIGS. 5 and 6. In such processes, the gasification unit, shown as
gasifier 120, produces a raw synthesis gas 122 from a carbonaceous feed 119,
such as coke or coal, to produce a synthesis gas comprising CO and H2, as well
as other contaminants that vary according to the feed stock.
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In a gaseous fuel synthesis process, the synthesis gas ("syngas")
provided by the process may have at least fifteen (15) mole percent hydrogen
gas. In other embodiments, the syngas provided by the process may have at
least twenty five (25) mole percent hydrogen gas therein. Depending on feed
stock, and the process employed, a synthesis gas provided by the process may
have at least thirty (30) mole percent hydrogen gas. In yet other feed stocks
or
operating conditions, the synthesis gas may have at least fifty (50) mole
percent
hydrogen gas. In still other embodiments, the synthesis gas may have at least
sixty five (65) mole percent hydrogen gas. In yet other embodiments, the
synthesis gas may have at least seventy five (75) mole percent hydrogen gas,
or
more than seventy five (75) mole percent hydrogen. In some gaseous fuel
synthesis plants, the synthesis gas may be provided at about one hundred (100)
mole percent hydrogen.
When a carbonaceous feedstock such as a coal or coke feedstock is
utilized in a gasification process, a raw synthesis gas may be cleaned at gas
cleanup unit 124 to produce a clean synthesis gas 126. A gas turbine 128' is
provided coupled to an electrical generator 159, for generating electrical
power.
The gas turbine engine 128' includes a compressor section 133', a turbine
162',
and a novel trapped vortex combustor 10. The novel trapped vortex combustor
10 is sized and shaped for receiving a gaseous fuel F including gas resulting
from the cleanup of the raw synthesis gas, via a fuel outlet 18 and a
compressed
oxidant containing stream A (see FIG. 1) and for mixing the gaseous fuel F and
the compressed oxidant containing stream A to form a premixed fuel and oxidant
stream 22 having a stoichiometric excess of oxidant. Then, the lean premixed
fuel and oxidant stream 22 is fed to the novel trapped vortex combustor 10 at
a
bulk fluid velocity 20 in excess of the speed of a flame front in a premixed
fuel
and oxidant mixture stream of preselected composition.
As shown in FIG. 1, noted above, the novel trapped vortex combustor 10
includes a first bluff body 14 and a second bluff body 16. The combustion of
the
synthesis gas occurs at least in part in cavity 12 to produce a stabilized
vortex 24
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and 26 of mixed oxidant and burning synthesis gas between the first bluff body
14 and the second bluff body 16.
In some embodiments, the bulk premixed velocity 20 may be in the range
of from about one hundred five (105) meters per second to about one hundred
fifty (150) meters per second (about 344.48 ft/sec to about 492.12 ft/sec).
The
fuel F in the lean premixed stream 22 is combusted in the novel trapped vortex
combustor 10, primarily at main vortex 12, to create a hot combustion exhaust
gas stream 164. The turbine 162' is turned by expansion of the hot combustion
exhaust gas stream 164, to produce shaft power, and the shaft 128's turns the
electrical generator 159 to produce electrical power.
Referring now to FIG. 6, when employed in an IGCC plant, an air
separation unit 131 is normally provided to separate air into a nitrogen rich
stream and an oxygen rich stream. In such IGCC plant, the oxygen rich stream
is provided as a feed stream to the gasification unit 120. In some
embodiments,
a motor 140 driven air compressor 142 may be provided to produce compressed
air 134 for feed to the air separation plant 131. As noted in FIG. 5, in some
embodiments, a compressor 142" having multiple compression stages and an
intercooler 176 can be provided, and in such case, the process can be operated
to recover the heat of compression from air compressed in the motor driven air
compression plant 142". Further, nitrogen can be collected from the nitrogen
rich stream exiting the air separation plant 131. In some embodiments, the
nitrogen can be stored as compressed gas, or liquefied, and in any event,
collected and either used elsewhere on site or sent off-site for sale.
In summary, whether for application for combustion of syngas from coal
gasification, or for combustion of other high hydrogen content fuels, or for
combustion of other gaseous fuels, a novel trapped vortex combustor design has
now been developed, and initial tests have indicated that significant
improvements in emissions may be attained in such a design. And, an important
objective of the novel trapped vortex combustor design and operating strategy
is
to control such emissions. In one embodiment, NOx is expected to be controlled
to about 15 ppmvd or lower. In another embodiment, NOx is expected to be
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controlled to 9 ppmvd or lower. In yet another embodiment, NOx is expected to
be controlled to 3 ppmvd or lower. These emissions are stated in parts per
million by volume, dry, at fifteen percent (15%) oxygen ("ppmvd").
As generally described herein, the novel trapped vortex combustor 10
described herein is easily adaptable to use in a power generation system.
Where syngas is burned, the fuel composition may vary widely, depending upon
the gasification process selected for use, but broadly, gaseous fuels may have
a
hydrogen to carbon monoxide mole percent ratio of from about 1/2 to about 1/1.
More generally, the novel trapped vortex combustor 10 described herein may be
sized and shaped for operation with a gaseous syngas fuel in a wide range of
fuel compositions, and in various embodiments, may be utilized on syngas
containing hydrogen, or more broadly, with fuels containing hydrogen in the
range of from about fifteen (15) mole percent to about one hundred (100) mole
percent.
The novel trapped vortex combustor 10 design described herein is a
unique design which allows use of a gaseous fuel lean pre-mix, and is capable
of
handling the high velocity through flow necessary with hydrogen-rich fuels.
The
technology has experimentally proven to be very stable and exhibits both low
pressure drop and low acoustic coupling throughout its operating range. It is
believed that these capabilities can potentially allow a gas turbine combustor
to
burn hydrogen-rich syngas type fuels in a lean pre-mix mode without flashback.
Further such an approach will enable the gas turbine combustor to meet the
stringent emissions requirements without after-treatment, and without diluent
gas. Such a configuration may also allow the retrofit of certain existing
natural
gas fired power plants to clean coal gasification operations, allowing for
productive use of the assets currently considered "stranded" by the high cost
of
natural gas.
In the foregoing description, for purposes of explanation, numerous details
have been set forth in order to provide a thorough understanding of the
disclosed
exemplary embodiments for a novel trapped vortex combustor, and power
generation systems employing such a trapped vortex combustor. However,
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certain of the described details may not be required in order to provide
useful
embodiments, or to practice a selected or other disclosed embodiments.
Further,
the description includes, for descriptive purposes, various relative terms
such as
adjacent, proximity, adjoining, near, on, onto, on top, underneath,
underlying,
downward, lateral, base, ceiling, and the like. Such usage should not be
construed as limiting. That is, terms that are relative only to a point of
reference
are not meant to be interpreted as absolute limitations, but are instead
included
in the foregoing description to facilitate understanding of the various
aspects of
the disclosed embodiments of the present invention. And, various steps or
operations in a method described herein may have been described as multiple
discrete operations, in turn, in a manner that is most helpful in
understanding the
present invention. However, the order of description should not be construed
as
to imply that such operations are necessarily order dependent. In particular,
certain operations may not need to be performed in the order of presentation.
And, in different embodiments of the invention, one or more operations may be
eliminated while other operations may be added. Also, the reader will note
that
the phrase "in one embodiment" has been used repeatedly. This phrase
generally does not refer to the same embodiment; however, it may. Finally, the
terms "comprising", "having" and "including" should be considered synonymous,
unless the context dictates otherwise.
Importantly, the aspects and embodiments described and claimed herein
may be modified from those shown without materially departing from the novel
teachings and advantages provided by this invention, and may be embodied in
other specific forms without departing from the spirit or essential
characteristics
thereof. Therefore, the embodiments presented herein are to be considered in
all respects as illustrative and not restrictive or limiting. As such, this
disclosure
is intended to cover the structures described herein and not only structural
equivalents thereof, but also equivalent structures. Numerous modifications
and
variations are possible in light of the above teachings. Therefore, the
protection
afforded to this invention should be limited only by the claims set forth
herein,
and the legal equivalents thereof.
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