U.S. patent number RE35,061 [Application Number 08/202,614] was granted by the patent office on 1995-10-17 for dry low no.sub.x hydrocarbon combustion apparatus.
This patent grant is currently assigned to General Electric Company. Invention is credited to Sanjay M. Correa.
United States Patent |
RE35,061 |
Correa |
October 17, 1995 |
Dry low NO.sub.x hydrocarbon combustion apparatus
Abstract
A fuel with or without fuel bound nitrogen (FBN) is burned in a
high pressure machine (20 atm) comprising fuel and air compressors,
combustor and turbine at an ER of about 2-3 and temperature below
the threshold for creating thermal NO.sub.x. Prompt and FBN
NO.sub.x are avoided due to the rich mixture, having a dearth of O
and OH, producing CO and H.sub.2 and little CH. The turbine cools
the products to reduce their temperature. The cooled products are
mixed with the remaining air and burned at a temperature below the
thermal NO.sub.2 threshold temperature at an ER of about 0.6.
Commercial stand alone machines can be used for the rich and for
the lean combustors wherein air and fuel are supplied to the rich
combustor and only air and the cooled combustion products of the
rich machine are supplied to the lean combustor.
Inventors: |
Correa; Sanjay M. (Schenectady,
NY) |
Assignee: |
General Electric Company
(Schenectady, NY)
|
Family
ID: |
26986273 |
Appl.
No.: |
08/202,614 |
Filed: |
February 28, 1994 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
Issue Date |
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328213 |
Mar 24, 1989 |
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Reissue of: |
606248 |
Oct 31, 1990 |
05103630 |
Apr 14, 1992 |
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Current U.S.
Class: |
60/792; 60/39.17;
60/39.181; 60/774 |
Current CPC
Class: |
F02C
3/28 (20130101); F02C 3/36 (20130101); F02C
6/003 (20130101); F23C 6/04 (20130101) |
Current International
Class: |
F02C
3/00 (20060101); F02C 3/26 (20060101); F02C
3/28 (20060101); F02C 3/36 (20060101); F02C
6/00 (20060101); F23C 6/04 (20060101); F23C
6/00 (20060101); A02C 003/10 () |
Field of
Search: |
;60/39.04,39.02,39.17,39.161,39.181 |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
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120206 |
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Mar 1984 |
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EP |
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950613 |
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Oct 1956 |
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DE |
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8700630 |
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Nov 1988 |
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NL |
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861924 |
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Mar 1961 |
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GB |
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1064182 |
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Apr 1967 |
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GB |
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2047265 |
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Nov 1980 |
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GB |
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Other References
Carlstrom, L. A. et al., "Improved Emissions Performance in Today's
Combustion System", AEG/SOA 7805, International Seminar, Jun. 1978,
pp. 1 and 17. .
Prediction and Measurement of a Non-Equilibrium Turbulent Diffusion
Flame, Correa et al., 20th Symposium (International) on
Combustion/The Combustion Institute, 1984, pp. 337-343. .
Nitric Oxide Formation from Thermal and Fuel-Bound Nitrogen Sources
in an Turbulent Nonpremixed Syngas Flame, Drake et al., 20th
Symposium (International) on Combustion/The Combustion Institute,
1984/pp. 1983-1990. .
NO.sub.x Formation in Lean Premixed Methane Flanes, Correa,
89CRD001, Jan. 1989. .
Low NO.sub.x Heavy Fuel Combustor Concept Program Phase IA Gas
Test, Final Report, Apr. 1981..
|
Primary Examiner: Nelson; Peter A.
Attorney, Agent or Firm: Webb, II; Paul R.
Parent Case Text
This application is a continuation of application Ser. No.
07/328,213, filed Mar. 24, 1989, and now abandoned.
Claims
What is claimed is:
1. Gas turbine apparatus for dry low NO.sub.x combustion
comprising:
a first gas turbine set including a first compressor means for
compressing incoming air to about 20 atmospheres, a first combustor
having fuel injector means and being coupled to said first
compressor means, said first combustor having an exit equivalence
ratio of about 2.0 to 3.0 so as to produce hot combustion products
comprising substantially CO and H.sub.2 and negligible NO.sub.x,
and first turbine means coupled to the output of said first
combustor for cooling the hot combustion products below a
temperature at which ignition and thermal NO.sub.x occur; and
a second gas turbine set including a second compressor means for
compressing incoming air to about 10 atmospheres, a mixer coupled
to said second compressor means for receiving air from said second
compressor means, said mixer also coupled to the output of said
first turbine means, the output pressure of said first turbine
means being about 5% higher than the output of said second
compressor .Iadd.means.Iaddend., so that rapid and homogeneous
mixing in the mixer is assured, a second combustor having fuel
injector means coupled to the output of said mixer, said second
combustor having an exit equivalence ratio of about 0.2 to 0.3, so
that production of NO.sub.x and CO is minimized, and second turbine
means coupled to the output of said second combustor.
2. The gas turbine apparatus of claim 1, wherein the quantity of
air supplied by said second compressor means is approximately ten
times the quantity of air supplied by said first compressor
means.
3. The gas turbine apparatus of claim 2 wherein the temperature of
the output of said first compressor means is approximately
840.degree. F. and the temperature of the output of said second
compressor means is approximately 600.degree. F.
4. The apparatus of claim 3 wherein the temperature of the
combustion products at the exit of the first turbine means is
approximately .[.1860.]. .Iadd.2136.Iaddend..degree. F. at a
pressure of 10.5 atmospheres and the temperature of the combustion
products at the exit of the second turbine means is approximately
1005.degree. F. at a pressure of 1 atmosphere.
5. A gas turbine apparatus for dry low NO.sub.x combustion
comprising:
a compressor for compressing incoming air;
a first combustor connected to said compressor for receiving a
portion of the compressed air from the compressor and having fuel
injection means for receiving fuel, said first combustor having an
exit equivalence ratio of about 2.0 to 3.0 so as to produce hot
combustion products comprising substantially CO and H.sub.2
.Iadd.and .Iaddend.negligible NO.sub.x ;
cooling means connected to said first combustor for cooling the hot
combustion products below a temperature at which ignition and
thermal NO.sub.x occur;
a mixer having inlet means and outlet means, said inlet means being
connected to said cooling means for receiving the cooled combustion
products and to said compressor for receiving the remaining portion
of the compressed air;
a second combustor connected to said outlet means of said mixer for
receiving the output of said mixer, said second combustor having an
exit equivalence ratio of about 0.2 to 0.3 so that production of
NO.sub.x and CO is minimized; and
turbine means connected to said second combustor for being driven
by the output of said second combustor. .Iadd.
6. A gas turbine apparatus for dry low NO.sub.x combustion
comprising:
a compressor for producing first and second portions of combustion
air;
a first combustor receiving said first portion of combustion air
and a fuel and in which combustion products are produced;
cooling means connected to said first combustor for cooling said
combustion products;
a second combustor receiving said cooled combustion products and
said second portion of combustion air, said second combustor having
an exit equivalence ratio sufficiently low so that very little
NO.sub.x is generated in a lean combustion process; and
a turbine driven by the products of combustion from said second
combustor. .Iaddend. .Iadd.7. The gas turbine apparatus for dry low
NO.sub.x combustion of claim 6 wherein said second combustor
includes a mixer in which said cooled combustion products and said
second portion of combustion air are mixed. .Iaddend. .Iadd.8. A
gas turbine apparatus for dry low NO.sub.x combustion
comprising:
a first compressor for producing a first portion of combustion
air;
a second compressor for producing a second portion of combustion
air;
a first combustor receiving said first portion of combustion air
and a fuel and in which combustion products are produced;
cooling means connected to said first combustor for cooling said
combustion products;
a second combustor receiving said cooled combustion products and
said second portion of combustion air, said second combustor having
an exit equivalence ratio sufficiently low so that very little
NO.sub.x is generated in a lean combustion process; and
a turbine driven by the products of combustion from said second
combustor.
.Iaddend. .Iadd.9. The gas turbine apparatus for dry low NO.sub.x
combustion of claim 8 wherein said second combustor includes a
mixer in which said cooled combustion products and said second
portion of combustion air are mixed. .Iaddend. .Iadd.10. A method
of generating power comprising the steps of:
burning a fuel with a first portion of combustion air in a first
combustor to produce combustion products;
cooling said combustion products;
burning said cooled combustion products with a second portion of
combustion air in a second combustor at an equivalence ratio
sufficiently low so that very little NO.sub.x is generated in a
lean combustion process; and
driving a turbine with the products of combustion of said second
combustor. .Iaddend.
Description
This invention relates to hydrocarbon fuel burning processes and,
more particularly, to such processes which include methodology for
reducing NO.sub.x combustion products.
Hydrocarbon fuel burning processes are widely used in stationary
power-generating gas-turbine systems. Combustion by-products which
pollute the atmosphere are required to be minimized as pan of a
growing concern about the quality of the earth's atmosphere.
Therefore, combustors for stationary power-generating gas-turbine
systems are required to produce low levels of nitric oxides (NO,
NO.sub.2, N.sub.2 O, etc., collectively referred to as NO.sub.x)
and of CO. Such emissions lead to acid rain and other environmental
problems. The NO.sub.x can result from reactions with atmospheric
nitrogen, such reactions being referred to as "thermal" and
"prompt" NO.sub.x, or with fuel-bound nitrogen (FBN). According to
well-supported combustion theory, NO.sub.x produced by the
"thermal" mechanism is due to atmospheric nitrogen being fixed by
the radicals responsible for flame initiation and propagation, as
shown by the following:
with the net reaction rate approximately given by ##EQU1## in
System International (S.I.) units. Because of the large activation
energy in the exponential term, the formation rate of NO.sub.x is
not significant below about 2780.degree. F., accounting for the
descriptor "thermal".
The concentration of certain radical species is also important,
particularly at low (on the order of atmospheric) pressures. The
radicals can exist in superequilibrium concentrations as discussed
in an article by S. M. Correa et al., entitled "Prediction and
Measurement of a Non-equilibrium Turbulent Diffusion Flame,"
Twentieth (International) Symposium on Combustion, The Combustion
Institute, pp. 337-343, 1984, and augment the thermal NO.sub.x
mechanism. Since radical consumption reactions speed up at the
relatively high pressures in power-generating systems, the degree
of superequilibrium and the resultant excess radicals are reduced.
For a further discussion on the formation of thermal NO.sub.x see
the following articles: M. C. Drake et al., "Superequilibrium and
Thermal Nitric Oxide Formation in Turbulent Diffusion Flames",
Comb. Flame, 69, pp. 347-365, 1987; "Nitric Oxide Formation from
Thermal and Fuel-Bound Nitrogen Sources in a Turbulent Non-Premixed
Syngas Flame," Twentieth Symposium (Int.) on Combustion, The
Combustion Institute, Pittsburgh, Pa., 1983-1990, 1984 and S. M.
Correa, "NO.sub.x Formation in Lean Premixed Methane Flames",
Engineering Systems Laboratory, 89CRD001, January 1989.
The preponderance of thermal NO.sub.x in conventional (fuel and air
not premixed) combustors, due to the high temperatures in the
turbulent mixing interfaces, has led to water or steam injection
for NO.sub.x control. In this approach, the injected water or stem
absorbs heat, reduces the peak temperatures (to below the NO.sub.x
-forming threshold) and so reduces NO.sub.x emission levels. The
lower temperatures have the undesirable side effect of quenching CO
consumption reactions and so the CO levels increase and combustor
life and efficiency are reduced. Thus the water or steam injection
technique is not ideal.
Prompt NO.sub.x is so named because it is formed very rapidly (in
hydrocarbon flames) when atmospheric nitrogen is fixed by alkyl
radicals, e.g., CH, CH.sub.2, CH.sub.3. The latter occur in the
hydrocarbon combustion kinetic chain. The nitrogen is fixed as
cyanide (HCN, CN) species which lead to NH.sub.i species and are
eventually oxidized to NO.sub.x by oxygen-containing radicals. The
mechanism does not require the high temperatures of the thermal
mechanism and so prompt NO.sub.x is not amenable to control by
water or steam injection. FBN NO.sub.x is very similar in that the
fuel-bound nitrogen species are extracted as NH.sub.i species which
are oxidized to NO.sub.x. FBN occur for example, in coal, and also
in so-called "dirty" gas derived from coal. However, prompt
NO.sub.x is not as much a problem as FBN. In typical applications,
FBN NO.sub.x can be on the order of 500 ppm or more, while
(conventional) combustors with non-FBN fuel have 100-300 ppm
thermal NO.sub.x and 10-30 ppm prompt NO.sub.x. It would be
desirable to burn dirty (FBN) fuel with <100 ppm NO.sub.x and
clean fuel with <10 ppm NO.sub.x.
Powerplant constraints dictate that the stability, turn-down ratio
(i.e. power changes corresponding to power demand reductions) and
efficiency be similar to those of current equipment. NO.sub.x
control techniques without water or steam injection are referred to
as "dry" combustion. Two dry low-NO.sub.x combustion techniques
have been suggested (i) rich-lean staged combustion (originally
intended for thermal and FBN NO.sub.x control but not successful
for the reasons discussed below) and (ii) lean premixed combustion
(intended for thermal NO.sub.x control).
In rich-lean staged combustion, the combustor is divided into a
first zone which is rich (equivalence ratio
.PHI..congruent.1.3-1.8; note that .PHI.=1 for stoichiometric
conditions, .PHI.>1 being rich and .PHI.<1 being lean) and a
second zone which is lean. Because of the off-stoichiometric
conditions, temperatures in each zone are too low for NO.sub.x,
(e.g. less than 2780.degree. F.) to form via the "thermal"
mechanism.
However in prior art staged systems, the mixing of air with the
efflux of the rich zone occurs at finite rates and cannot prevent
the formation of hot near-stoichiometric eddies. The attendant high
temperatures lead to the copious production of thermal NO.sub.x,
which is triggered at temperatures above about 2780.degree. F. This
has been the experience both in the laboratory and in mainframe
(100 MW class) gas-turbine equipment. However, rich combustors are
suitable for fuels with a significant fuel-bound nitrogen content
because the amount of oxygen available to produce FBN NO.sub.x is
limited.
Lean premixed combustors, which are useful if the fuel does not
contain nitrogen, are fueled by a lean (prevaporized, if liquid
fuel) premixed fuel-air stream at .PHI..congruent.O.7. The ensuing
temperatures are uniformly too low (e.g., less than 2780.degree.
F.) to activate the thermal NO.sub.x mechanism. Detailed chemical
kinetic studies of two such combustors by the present inventor have
lead to the discovery that most of the NO.sub.x is produced by the
"prompt" NO.sub.x mechanism described above (recall that FBN is not
present). This forms a lower limit to the minimum NO.sub.x
obtainable in current hydrocarbon-fueled combustors. Advanced
combustors under development by the assignee of the present
invention have reached an apparent 30-40 ppm NO.sub.x barrier
(using clean natural gas which minimizes total NO.sub.x
production). This barrier can be crossed only with an increase in
CO and an unacceptable loss of flame stability. Such (lean)
combustors also produce unacceptably high levels of NO.sub.x from
FBN species in the fuel if FBN species are present. Thus each of
the prior art systems has advantages and disadvantages.
According to the present invention, the efflux of a rich combustor
is cooled to prevent ignition during mixing to a lean condition.
Ignition and flame stabilization occur only after the lean mixture
has been established. According to one embodiment, a portion of the
air is burned under rich conditions (e.g., overall equivalence
ratio, .PHI.=2.5-3.0) in a preburner to produce a partially
combusted stream which contains CO and H.sub.2, referred sometimes
as syngas, and very little CH.sub.4 (the original fuel), CO.sub.2
and H.sub.2 O. The hot gas stream is then cooled by way of example
by expansion through a turbine or passage through a heat exchanger.
The cooled gas stream is then mixed with the remaining portion of
the air stream, without ignition. The lean stream (e.g.,
.PHI.=0.5-0.6) is then burned.
The production of NO.sub.x is minimized due to the relatively cool
temperatures in the rich and lean burning cycles, which
temperatures are below the established level for the production of
thermal NO.sub.x. Prompt NO.sub.x is also minimized since CH in the
lean cycles tends to be negligible. FBN NO.sub.x is minimized
because the rich combustor runs with too little oxygen for
production of NO.sub.x.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a schematic diagram of a combustion cycle in accordance
with one embodiment of the present invention; and
FIG. 2 is a schematic diagram of a combustion cycle in accordance
with a second embodiment of the present invention.
In the schematic diagram of FIG. 1, a representative combustion
system in accordance with one embodiment of the present invention
is illustrated. In the system shown a main combustion machine 10
comprises a compressor 12, a gas mixer 14 and a primary combustor
16 whose combustion products drive turbine 18. A system comprising
compressor 12, mixer 14, combustor 16 and turbine 18 are
commercially available mainframe machines, which for example, may
be a General Electric Company MS7000 series machine for driving a
100 megawatt class electrical generator. A second combustor 20 is
coupled to receive 100% of the fuel at in inlet thereof which fuel
preferably is methane, coal or coal derived gas or a liquid
hydrocarbon fuel. The output of combustor 20 is applied to a gas
cooling stage 22 which may comprise a turbine or expansion nozzles
to cool the gas produced by the combustor 20. The inlet of
combustor 20 receives x% of air from the compressor 12. The
remaining portion of the air 100-x% is applied to the mixer 14 of
the mainframe machine 10.
Combustor 20 may be similar in construction as the combustor in a
commercially available gas turbine generator known as a General
Electric Company model LM500. The LM500 however, includes a fuel
compressor and air compressor for compressing the fuel and air
supply to the combustor 20. In the embodiment of the machine 10
however, the air compressor is not included as the air is
compressed via compressor 12 and the fuel is compressed and
supplied to the input of combustor 20. The cooling stage 22 may
include a turbine as available in the model LM500 gas generator.
However, a turbine is not essential for the gas cooling stage as
indicated above.
100% of the fuel is applied to the combustor 20 which burns that
fuel in a rich combustion mixture with a relatively low mount of
air supplied via the compressor 12. For example, the amount of air
supplied to combustor 20 may be 10% of the air supplied to the
mixer 14 from compressor 12. The combustion products are applied to
the cooling stage 22 while at a relatively hot temperature. The
temperature is below about 2780.degree. F. at which thermal
NO.sub.x is generated. Because of the rich combustion, little
oxygen is available for the combustion process in combustor 20 and
the temperature thereof does not exceed the threshold temperature
at which thermal NO.sub.x is generated. The relatively rich
characteristics of the burning process generates little 0, OH and
other oxidizing radicals in the burning process minimizing prompt
NO.sub.x. Also, the rich combustion process favors reforming
chemistry, i.e. tends to avoid the generation of CH gas products;
instead produces gas products comprising primarily CO and H.sub.2.
The CO and H.sub.2 mixture is commonly referred to as syngas or
synthetic gas. The FBN species, if present, are converted to
N.sub.2 (molecular nitrogen).
The combustion efficiency of combustor 20 is believed to be
generally about 75% and therefore about 25% of the fuel in the
syngas products remains unburned. Combustor 20 because it is
relatively rich operates at an equivalence ratio (ER) of
approximately 2.5-3. Of course, the equivalence ratio will vary
between the head end and the exit of the combustor 20. The exit ER
is in the range indicated, the head end being lower, within the
rich stability limit. The combustor 20 is illustrative of a more
complex system in which a staged combustor may be provided with
more fuel added to the products of a rich primary zone having a
.PHI. of approximately 2. The added fuel promotes "reforming"
chemistry. Because the temperature is below the threshold value for
the generation of thermal NO.sub.x, such thermal NO.sub.x is
substantially negligible at the output of combustor 20. The
combustor process maximizes CO and H.sub.2 and fuel conversion.
The cooling stage 22 may be either a turbine or a heat exchanger to
cool the hot syngas produced by the combustor 20 and deliver power
or heat as my be required in a given implementation. The output of
such a turbine or heat exchanger is such to cool the syngas to a
temperature below ignition temperatures before delivery to the
mixer 14 in the system 10. This step is critical.
In accordance with the principles of the present invention, the
syngas produced by the rich combustor 20 has negligible total
NO.sub.x because of the low temperature and the lack of oxidizing
species. FBN species are convened to N.sub.2. However, in the
transition to the mixer 14 it is important that the syngas be
reduced to a temperature sufficiently low that the temperatures in
the process of turbulent mixing in mixer 14 remain below the
threshold for the generation of thermal NO.sub.x. Without the
cooling produced by stage 22 the hot syngas produced by the
combustor 20 when mixed with air in the mixer 14 could lead to
ignition and flame in mixer 14 and to copious thermal NO.sub.x.
Because there is little CH component in the syngas product of the
combustor 20, there is little prompt NO.sub.x in the system 10.
It should be understood that the combustors 16 and 20 include more
complex combustion systems including primary burners (head ends)
and downstream addition of air in the case of combustor 16, per
conventional practice, and downstream addition of fuel in the case
of combustor 20. Assuming a preburner is included in the combustor
20, then the cooling stage 22 may be provided .Iadd.by .Iaddend.a
pressure reducing nozzle which will increase the usual
approximately 4% pressure drop available for mixing. Air needed to
premix to lean main-combustor conditions is admitted via jets
within such a nozzle (not shown). With the use of a nozzle,
integration may be accomplished because the cooling and premixing
can both occur within the nozzle. In this case the mixer 14 would
be combined in such a nozzle with the mixing occurring in the
nozzle. Otherwise the mixer 14 mixes the cooled syngas which is at
a temperature below the 2780.degree. F. threshold temperature for
the generation of thermal NO.sub.x, and mixes that air gas at
compressor temperature, for example, 600.degree. F.
The mixing of the syngas with most of the air stream produces a
lean premixed stream having an equivalence ratio .PHI. of
approximately 0.5 at the head end of the combustor 16 and about 0.3
at the exit. The mixing process of mixer 14 or nozzles (not shown)
is at a sufficiently low temperature so that a flame and thermal
NO.sub.x cannot be formed during dilution.
Relatively negligible mounts of hydrocarbons are available at the
mixer 14 since only air from the compressor 12 is added at the
mixer 14 to the syngas produced by the combustor 20. Therefore,
very little prompt NO.sub.x is generated in combustor 16. The
particular operating points for the fuel and air mixers and
pressures and temperatures can be selected by analysis and
experimental variations of the components for a given
implementation. In particular, the stoichiometries of the
combustors 16 and 20 are optimized for producing maximum power at
the turbine 18. Not shown is an electrical generator or other
utilization means coupled to the turbine 18 and driven thereby.
Because the generation of hydrocarbons and FBN NO.sub.x are
minimized in the syngas output or the cooling stage 22 and because
the generation of the thermal NO.sub.x is minimized by maintaining
the temperatures below the threshold, the fuel supplied to
combustor 20 may comprise coal gas, liquid fuels and other types of
fuels with relatively high fuel bound nitrogen. Employing the
process as discussed above in connection with FIG. 1, the fact that
the fuels used in the combustor 20 are rich in nitrogen will not
affect the resulting products in the syngas at the output of the
cooling stage 22. Nitrogen in FBN species will be converted to
N.sub.2.
By way of example, combustor 20 may be supplied with approximately
0.5 lbs. per second of methane (CH.sub.4) accompanied with 2.5 lbs.
per second of air. The combustor 20 as mentioned above has an
overall equivalence ratio of about 3. The syngas output of the
cooling state 22 comprises approximately a flow rate of 1 lb. per
second of carbon monoxide plus hydrogen (CO+H.sub.2) the rest being
mostly N.sub.2 (nitrogen). This is combined with about 15 lbs. per
second of air which is applied to the mixer 14. Air for providing
dilution and cooling is provided to the combustor 16 at
approximately 7.5 lbs. per second to provide a downstream exit
equivalence ratio .PHI. of approximately 0.3. This process yields
an approximate NO.sub.x level of 5 ppm NO.sub.x. It should be
understood that the combustors 20 and 16 are supplied fuel and air
at various inputs at the head end and downstream inputs in
accordance with conventional combustors. Combustor 16 uses air for
downstream inputs while combustor 20 uses fuel for downstream
inputs.
In FIG. 2, a second embodiment employing two stand alone
commercially available combustion machines are employed for
implementing the present invention. A compressor 200 compresses all
of the hydrocarbon fuel such as methane to a pressure of about 20
atmospheres and applies the compressed fuel to combined combustor
mixer 202. The compressor 204 supplies a portion x% of the total
air required overall. Compressor 204 supplies the compressed air to
the combustor 202. Combustor 202 consists of a head end operated
near the rich limit with downstream addition of more fuel to
achieve the required stoichiometry. By way of example, x may be 10%
of the air required overall. Combustor 202 burns the fuel air
mixture and applies the burned combustion products to a turbine
206. The purpose of the turbine 206 is similar to the cooling stage
22 of FIG. 1 which provides cooling of the hot combustion gases to
produce a cooled carbon monoxide (CO) and hydrogen (H.sub.2)
syngas. The cooled syngas is applied to the input of mixer 208. The
remaining air required is applied to compressor 210. For example,
where 10% of the air is applied to compressor 204, 90% of the air
required to burn overall is applied to compressor 210. Compressor
210 provides a pressure of about 10 atmospheres to the air supplied
to the mixer 208. Mixer 208 mixes the air from compressor 210 with
the cooled syngas from turbine 206. The mixed cooled gas product is
applied to combustor 212 whose hot gas products are exhausted to a
turbine 214 which drives a generator (not shown).
In one calculation example to verify the process, a 0.5 lbs per
second of methane is supplied as the fuel to compressor 200. This
is applied at atmospheric pressure at room temperature (60.degree.
F.). To this is added 0.3% NH.sub.3 (ammonia). The ammonia
represents fuel bound nitrogen in a coal derived gaseous fuel. The
efficiency of fuel compressor 200 is assumed approximately 0.9. The
output of compressor 200 has a temperature of about 677.degree.
F.
Compressor 204 compresses 2.86 lbs. per second of air supplied at
atmospheric pressure at room temperature. The output of compressor
204 is at approximately 842.degree. F. with the outputs of both
compressors 200 and 204 at 20 atmospheres. Combustor 202 mixes the
fuel and air and burns the combination with .PHI. at about 2.0 at
the head end and 3.0 at the exit port. The output of the rich
combustor 202 has a temperature of about 2520.degree. F. It is
calculated that the products from the combustor 202 have less than
1 ppm NO.sub.x which value increases as the equivalence ratio
decreases. It is also estimated that there are about 750 ppm
NH.sub.i, HCN. The gas products from combustor 202 are applied to
turbine 206 which runs at about a 2 to 1 pressure ratio which
serves to cool the combustor gas products, producing a cooled
syngas on line 207.
Combustor 202 burns a rich fuel air mixture to which more fuel is
armed in the downstream region of the combustor. This leads to
reduction of the initial products by the fuel added downstream. The
process is referred to as "reforming" chemistry such that the
products of the syngas on line 207 are primarily CO and H.sub.2
rather than fuel and combustion products. The NO.sub.x emissions
are low on line 207 due to the relatively low temperatures and lack
of oxidizing radical species such as O and OH in combustor 202.
This has been verified by laboratory experiments and kinetic
studies. The output pressure of the turbine 206 on line 207 is at
about 10.5 atmospheres and at a temperature of about 2136.degree.
F. If the equivalence ratio in the head end of combustor 202 is
made too high, the flame can become unstable in the combustor.
There may also be excessive soot because the combination of gas,
fuel and air is too rich. Further, there can be excessive
production of NO.sub.x as the .PHI. is lowered. For this reason, it
is preferred that the head end .PHI. of combustor 202 be in the
range of 2 to 2.5, with more fuel added downstream.
Compressor 210 receives the remaining air. This air is applied to
compressor 210 at a rate of 25.74 lbs. per second, in this example,
at room temperature and atmospheric pressure. Compressor 210
operates at an efficiency of 0.9. The output pressure of compressor
210 is 10 atmospheres at a temperature of about 600.degree. F. This
air is mixed in mixer 208 with the cooled syngas and applied to
lean combustor 212. The lean combustor 212 has a head end .PHI. of
about 0.6 and an exit .PHI. of about 0.3. Combustion products at
the exit of combustor 212 are at about 1860.degree. F., and exhibit
approximately 58 ppm NO.sub.x and less than 1 ppm CO. Recall that
the fuel contained FBN (0.3%). Turbine 214 operates with an assumed
efficiency of 0.9 and has an output temperature of about
1005.degree. F. at one atmosphere. The 58 ppm NO.sub.x and less
than 1 ppm CO products produced by the combustor 212 is considered
excellent in view of the combustion of dirty fuel containing 3%
ammonia applied to the compressor 200. Normally, such dirty fuel
will produce hundreds of ppm of NO.sub.x. Of course, different
ratios of fuel, air and dirty fuel contaminants such as FBN will
produce different values of temperature at the different stages.
The 10% air applied to the compressor 204 and 90% air applied to
compressor 210 is believed optimum for one implementation. Turbine
214 is then employed to operate an electric generator or other
utilization means.
Turbine 206 causes expansion of the combustor output gases and
reduces the temperature of the syngas to a level where mixing can
be accomplished in mixer 208 without premature ignition. The
turbine 206 exit pressure is larger than the operating pressure of
the combustor 212 by about 5% (10.5 atm vs 10 atm) to facilitate
mixing of the syngas from line 207 and the air from compressor 210
to an overall lean condition. The figures given above with respect
to the proportions of fuel to air, efficiencies of the compressors
and turbines and approximate temperatures are based on calculations
of the various operating points, emissions and overall thermal
efficiency. The various assumptions are included in these
calculations as indicated.
The total fuel and air flow rate are consistent with combustor cans
in current mainframe power generation machines. Calculation of the
cycle efficiency of the embodiment of FIG. 2 shows the cycle
efficiency of 30.7% to be comparable to a base machine comprising
compressor 210, mixer 208 and combustor 212 with the same level
accuracy in the calculation, that is a cycle efficiency of 30.5%.
Slight improvement in the cycle efficiency is due in part to the
straight forward improvement of the Brayton cycle with the
designated pressure ratios, since the combustor 202 runs at 20
atmospheres pressure as compared to the 10 atmosphere pressure of
combustor 212.
* * * * *