Furnaces – Process – Treating fuel constituent or combustion product
Reexamination Certificate
2000-07-18
2002-03-19
Esquivel, Denise L. (Department: 3749)
Furnaces
Process
Treating fuel constituent or combustion product
C110S346000, C110S348000, C110S342000, C110S238000, C422S182000, C422S183000
Reexamination Certificate
active
06357367
ABSTRACT:
FIELD OF INVENTION
The invention relates to reducing NO
x
emissions from furnaces by addition of a water biofuel or waste fuel slurry to the furnace outside the primary combustion zone.
BACKGROUND OF THE INVENTION
During combustion of fuels with fixed nitrogen such as coal, oxygen from the air may combine with the nitrogen to produce nitrogen oxides (NO
x
). At sufficiently high temperatures, oxygen reacts directly with atmospheric nitrogen to form NO
x
. Emission of nitrogen oxide is regarded as undesirable because the presence of nitrogen oxide in a furnace flue gas (along with sulfur dioxides) causes the condensed gases to become corrosive and acidic. There are numerous government regulations which limit the amount of nitrogen oxide which may be emitted from a combustion furnace. Titles I and IV of the Clean Air Act as amended in 1990 (“The Clean Air Act”) require significant NO
x
reduction from large power plants. Title I of the Clean Air Act focuses on the problems of ozone non-attainment. Ozone is formed as a result of photochemical reactions between nitrogen oxides emitted from central power generating stations, vehicles and other stationary sources, and volatile organic compounds. Ozone is harmful to human health. Consequently, in many urban areas the Title I NO
x
. controls are more stringent than the Title IV limits. Thus, there is a need for apparatus and processes which reduce the nitrogen oxide emissions in furnace flue gas.
Commercially available techniques to reduce the nitrogen oxide emissions in a furnace flue gas are low NO
x
burners, overfire air, selective non-catalytic NO
x
reduction (SNCR), selective catalytic reduction (SCR), and reburning. Currently, retrofitting boilers with low NO
x
burners and overfire air is the most economic route to comply with Title IV requirements of the Clean Air Act. However, low NO
x
burners cannot reduce NO
x
emissions to levels required by Title I of the Clean Air Act. As a consequence, electric utilities are faced with the option of adding SNCR or reburning to the boiler. In addition, cyclone boilers cannot be retrofitted with low NO
x
burners. SCR, SNCR and reburning are the options for cyclone boilers.
The reburning process is also known as in-furnace nitrogen oxide reduction or fuel staging. The standard reburning process has been described in several patents and publications. See for example, “Enhancing the Use of Coals by Gas Reburning -Sorbent Injection,” submitted at the Energy and Environmental Research Corporation (EERC), First Industry Panel Meeting, Pittsburgh, Pa., Mar. 15, 1988; “GR-SI Process Design Studies for Hennepin Unit #1—Project Review,” Energy and Environmental research Corporation (EERC), submitted at the Project Review Meeting on Jun. 15-16, 1988; “Reduction of Sulfur Trioxide and Nitrogen Oxides by Secondary Fuel Injection,” Wendt, et al.; published at the Symposium of the Combustion Institute, 1972; “Mitsubishi ‘MACT’ In-Furnace NO
x
Removal Process for Steam Generator,” Sakai, et al.; published at the U.S. —Japan NO
x
Information Exchange, Tokyo, Japan, May 25-30, 1981. In reburning a fraction of the total thermal input is injected above the primary flame zone in the form of a hydrocarbon fuel such as coal, oil, or gas. A reburn zone stoichiometry of 0.90 (10% excess fuel) is considered optimum for NO
x
control. Thus, the amount of reburn fuel required is a direct function of the primary zone excess air. Under typical boiler conditions a reburn fuel input in the range of 15% to 25% is sufficient to form a fuel-rich reburn zone. The reburn fuel is injected at high temperatures in order to promote reactions under the overall fuel rich stoichiometry. Typical flue gas temperatures at the injection location are above 2600° F. Completion air is added above the fuel rich reburn zone in order to burn off the unburnt hydrocarbons and carbon monoxide (CO). In addition to the above specifications, the prior art on standard reburn teaches that rapid and complete dispersion of the reburn fuel in flue gas is beneficial. Thus, flue gas recirculation (FGR) has been used to promote mixing in all standard reburn demonstrations. Standard reburn technology requires a tall furnace to set up a fuel rich zone followed by a lean zone. Many furnaces do not have the volumes required for retrofitting this technology.
In current practice of the reburning process, usually more than enough fuel is added to react with all of the oxygen remaining in the original combustion products. A reducing zone, or a zone with an excess of fuel is formed. In this reducing zone the NO reacts with the excess fuel to form N
2
, NH
3
, HCN, and other reduced nitrogen. Then more air is added to combust the remainder of the reburn fuel. At this point the NH
3
, HCN, and other reduced forms are oxidized to N
2
and NO. At this step and throughout the mixing process there is also a direct reaction between NO and NH
3
to form N
2
. In each step part of the fixed nitrogen (originally NO) was converted to N
2
. This is the goal of the reburn process.
Sometimes a NO
x
. reduction process is used in which the upper furnace fuel is not added in sufficient qualities to consume all of the oxygen remaining in the gas after the initial combustion. In such a process it is necessary that large volumes become reducing while parallel volumes remain oxidizing. In the reducing volumes N
2
, NH
3
, and HCN are formed. Then the reducing and oxidizing gases mix together and the remainder of the fuel is consumed. At this point the reduced nitrogen species are oxidized to N
2
and NO. Again there is direct reduction to N
2
by the reaction between NH
3
and NO.
The process which is sometimes called controlled fuel lean reburn usually requires natural gas as the upper furnace fuel. Natural gas is expensive. Penetration and mixing is a great problem. Utility boiler furnaces have horizontal dimensions of 50 feet and greater. The carrier gas may be steam, air, or recycled combustion products. Often it is necessary to use a carrier gas to assure adequate penetration of the natural gas into the furnace. If the upper furnace natural gas is 5% of the fuel and the fuel is only 10% of the air flow, upper furnace injected natural gas is perhaps only 0.5% of the gas flow. The combustion products being quite hot may have a volume as high as 1000 times the upper furnace natural gas. Use of steam as a carrier gas is expensive. The use of air or recycled combustion products requires expensive duct work. Often there is no place for the duct work. The boiler face is simply too crowded with necessary equipment to allow the duct work to be installed. Large penetrations through the furnace walls are needed and this requires bending water wall tubes. The flue gas needs to be returned from a remote part of the boiler. Fans are needed for flue gas and often for air. Because air has oxygen in it, use of air as the carrier gas requires more upper furnace fuel before the gas stream can be made reducing.
Some operators have tried coal as a reburn fuel. The burnout times for coal are longer than for natural gas. This requires that both the fuel and the burnout air be added sooner. As a result, much of the reaction occurs at higher temperatures which results in more NO
x
emissions. The use of coal requires that there be additional pipes to carry primary air and pulverized fuel from the mills usually at ground level to the height where the reburn fuel is injected. It may even require an additional pulverizer.
A method of reducing NO
x
by injecting: a coal water slurry as a fuel lean reburn fuel has been patented, as U.S. Pat. No. 5,746,144, and that invention overcomes many of the objections to reburning with coal. Yet, this fuel requires longer burnout times than natural gas. Hence, there is still a need for a reburn fuel which has the benefits of a coal water slurry while also having a shorter burnout time.
SUMMARY OF THE INVENTION
We provide a method of reducing NO
x
emissions by injecting a biowaste water slurry, a biomass water slurry, waste rubber water slurry, waste plasti
Breen Bernard P.
Gabrielson James E.
Sweterlitsch Jeffrey J.
Buchanan Ingersoll P.C.
Energy Systems Associates
Esquivel Denise L.
Rinehart K. B.
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