Note: Descriptions are shown in the official language in which they were submitted.
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USE OF HYDROCARBON EMULSIONS AS A REBURN FUEL TO REDUCE
NOX EMISSIONS
BACKGROUND OF THE INVENTION
Field Of The Invention
The invention relates to a method of reducing NOX
emissions from various types of furnaces ranging from utility
boilers to industrial package boilers to Once Through Steam
Generators to refinery furnaces.
Description of Related Art
The art has long recognized the presence of NOx in
effluent gases from various types of hydrocarbon burning
devices and the desirability of reducing such NOX.
Masaki et al., USP 4,060,983, discloses that it is
well known to reduce the amount of NOX in an engine by
employing a non-stoichiometric air-fuel ratio [in
automobile engine]
Zamanshy et al., USP 6,471,506, utilizes metal
containing compounds in a furnace reburn zone to reduce NOX.
Zauderer, USP 6,453,830, reduces NOX by introducing
sufficient fuel into the furnace downstream of the primary
combustion zone into a fuel rich zone at a temperature that
favors the conversion of NOX to N2. Then further downstream
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air is added to complete combustion of any unburned fuel.
Additional fuel, where the fuel is pyrolysis gas from
the partial gasification of a solid fuel, is introduced
into a downstream combustion zone as solid particles
dispersed in aqueous droplets of varying size. In other
embodiments the fuel is a liquid fuel or is pulverized coal
or shredded biomass particles.
In Zamansky et al., USP 7,168,947, a fuel rich zone is
established containing a plurality of reduced n-containing
species, introducing over fire air downstream of the fuel
rich zone so that the n-containing species react with the
NOX in the overfire zone.
Arand et al., USP 4,325,924, introduces urea in the
presence of excess fuel as a solid or liquid at a
temperature in excess of 1900 F.
Hura et al., USP 5,908,003, burns a solid fuel in a
primary zone and injects a gaseous fuel into a downstream
fuel lean zone at a temperature of 1800 to 2400 F.
Breen et al., USP 6,213,032, injects a water-oil
emulsion into flue gas where the emulsion is 35-80% water.
Urea or water may be added to emulsion which is preferably
atomized before injection.
Payne et al., USP 6,481,998, discloses an apparatus
for high velocity injection of liquid fuel into an NOX
containing stream downstream of the primary combustion
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chamber without using recirculated flue gas or other
carrier gas.
Reburn is a combustion hardware modification in which
the NOX produced in the main combustion zone is reduced
downstream by providing a second combustion zone (the reburn
zone) . Up to 20% of the total fuel heat input to the
furnace may be diverted from the main combustion zone
and introduced above the top row of burners to create
reducing (sub-stoichiometric in 02 terms) conditions in
the reburn zone. The reburn fuel is typically natural gas
or micronized coal, a coal that is pulverized to 90%
through a 300-mesh screen. The reburn fuel is injected
into the furnace to create a fuel-rich zone where the NO
formed in the main combustion zone is reduced to N2, NH3,
HCN, other reduced nitrogen compounds and water vapor.
The reburn fuel may be injected alone or may be
injected with a carrying medium such as re-circulated
flue gas to improve fuel distribution in the furnace.
Combustion of the fuel-rich combustion gases
leaving the reburn zone is completed by injecting
overfire air (also called "completion air" when
referring to reburn) in the burnout zone. At this point
the NH3, HCN, and other reduced forms are oxidized to N2,
and NO. At this step and throughout the mixing process
there is also a direct reaction between NO and NH3 to form
N2. In each step, part of the fixed nitrogen (originally
NO) is converted to N2 thus fulfilling the purpose of the
reburn process.
The gas reburn principal can be implemented in several
ways. The traditional approach involves overall fuel-rich
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gas reburn. NO containing furnace gases from the primary
combustion zone enter a downstream gas mixing and reburn
zone in which a sufficient flow rate of natural gas is
injected to form an overall fuel-rich mixture,
Essentially, a region in the secondary combustion zone is
driven sub-stoichiometric.
The total fuel flow to the reburn zone of the furnace
is typically in the range of 10% to 20% of the total energy
input utilized in the furnace. Reburn reactions in the
overall fuel-rich NOX reduction reburn zone reduce NO to N2,
but produce relatively high levels of CO. Nitrogen in the
reburn zone enters from the combustion gases from the
primary combustion zone and from nitrogen contained in the
reburn fuel, if any.
This CO produced in the reburn zone is then reduced
in a final burnout zone by injecting completion overfire
air to produce overall lean conditions in which oxidation
of the reburn gas is completed. Such conventional gas reburn
technology has demonstrated NOX reductions above 50% in many
installations.
A related technology, the modified reburn process, can
achieve comparatively moderate NOX reductions, but at a much
lower heat input than in conventional reburn furnaces, and
without the need for a completion overfire air system to
achieve CO burnout. In the modified reburn process
technology, natural gas or an emulsion of water and oil is
injected into the upper furnace at sufficiently low rates to
maintain overall fuel-lean conditions in the upper furnace
region. The NOX reburning reactions then occur within local
fuel-rich regions formed by the gas injection and the mixing
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process.
Mixing between the injected reburn fuel and furnace
gas is key to effective N0X control. CO burnout is achieved
by the excess 02 available in the overall furnace flue gas,
without the need for a completion overfire air system. This
technology has achieved 35% to 40% NOX reductions at 7%
burnout fuel heat inputs without significant impact on the
primary furnace combustion process.
Successful application of this modified reburn
technology to any given installation hinges on achieving
proper mixing of the injected gas with furnace gases to
achieve optimum N0X removal and low CO emissions. Uniform
mixing of the injected gas will in most cases not produce
the highest N0X removal efficiencies. The N0X and CO
performance of this technology thus depends on the
location, size, shape and placement of the gas injectors,
which determine details of the resulting gas mixing
process. To date, the results indicate that maximum N0X
reductions of 35% at 7% maximum gas heat input levels are
limited by increased levels of CO emissions.
Attempts to maximize gas mixing are exemplified by the
high velocity fuel injectors specified in Payne et al. USP
6,481,998 issued November 19, 2002.
In those processes where a carrier gas is used to input
the reburn fuel, the carrier gas maybe steam, air, or
combustion products. Steam is expensive. The use of air or
recycled combustion products such as flue gas recirculation
requires expensive ductwork, or the need for an expensive
flue gas recirculation fan. These fans are expensive to
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operate and high maintenance items.
Micronized coal requires a long burnout time when
utilized as a reburn fuel. Utilizing micronized coal as a
fuel source requires that both the fuel and the completion
air be added at an earlier point in the furnace. As a
result, much of the reaction occurs at higher temperatures,
which results in more NOX emissions.
Where boilers use neat bitumen or heavy fuel oil as
the primary fuel, with high concentrations of vanadium in
the ash of the fuel, a SCR (Selected Catalytic Reduction)
process will not be practical due to the negative impact of
the vanadium (in the form of Va205) on the catalyst in the
SCR.
In addition, the need for completion air in traditional
reburn processes requires that boiler pressure parts be
modified (tube wall bending) which are expensive and can
impact boiler water flow circulation patterns and heat
transfer characteristics.
The first installation and combustion optimization of
natural gas as a reburn fuel in the first full-scale
utility boiler in the USA was accomplished in the Niles
Station of Ohio Edison in the late 1980's on a cyclone
boiler.
The Electric Power Research Institute (EPRI) issued a
report entitled "Gas Cofiring Assessment for Coal-Fired
Utility boilers, EPRI, Palo Alto, CA: 2000, (10000513)
considering the following:
= Gas Reburning (RB)
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= Fuel Lean Gas Reburning (FLGRTm)
= Amine Enhanced Fuel Lean Gas Reburning (ALFLGRIm)
= Advanced Gas Reburning (AGR)
= Supplemental gas cofiring
= Coal/Gas cofiring burners
Although all of these reburn methods reduce NOX
emissions the industry has been slow to adopt them.
Commercial technologies available for NOX reduction
have disadvantages that create boiler operational problems
or cannot achieve NOX levels below 0.15 lbs./MM Btu
without using two or more of these technologies.
Selected Catalytic Reduction can achieve lowest NOx
emissions levels but create operational and maintenance
problems that impact costs and boiler availability.
Low NOX Burners alone can not achieve the low NOx
levels alone without adding Over Fire Air as an example.
In addition, Low NOX Burners' firing refinery gas can
experience stability problems.
Over Fire Air creates the sub-stoichiometric
conditions that lead to the high temperature vanadium
corrosion attack.
Selected Non-Catalytic Reduction can not achieve low
NOx levels (primary objective) and has high ammonia slip.
Traditional Reburn creates the sub-stoichiometric
conditions that lead to the high temperature vanadium
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corrosion attack.
Advanced oil recovery methods, such as the Cyclic Steam
Stimulation process (CSS) and the Steam Assisted Gravity
Drainage (SAGD) process, use steam to extract oil in situ
through the use of injected steam. Boilers used in these
processes do not presently use reburn technology.
For many applications, the associated costs and
installation problems discussed above when considered
against the projected level of NOX emissions reduction has
not been perceived to be worth the investment.
Thus, there continues to be a need for a reburn
method/application which provides significant NOX emissions
reduction without requiring extensive duct work, FGR fans,
and modifications to the boiler pressure parts.
SUNIlKARY OF THE INVENTION
Provided are a method and apparatus for reducing NOX
emissions in which a bitumen containing aqueous emulsion
is injected into the flue gas of a furnace downstream of
the primary combustion chamber and combusted in an oxygen
poor reducing environment to remove a significant portion
of the NOx components in the combustion gases.
The disclosed method of introducing NOX reduction into
boilers used for the Steam Assisted Gravity Drainage oil
sands Steam Assisted Gravity Drainage application (OTSG &
package drum boilers), refinery furnaces, or utility
boilers will maintain overall stoichiometric conditions
above 1.0 throughout the boiler and specifically in the
primary furnace.
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All four of the current NOX reduction technologies -
Selected Catalytic Reduction, Low NOX Burners, Over Fire
Air, Selected Non-Catalytic Reduction and traditional
reburn - have serious problems when applied to the
boilers used for the Steam Assisted Gravity Drainage
process when using alternative fuels in oil sands
applications, refinery boilers and utility boilers.
The emulsion is a hydrocarbon in water emulsion where
the hydrocarbon component may itself be an emulsion of
varying composition in the aqueous component of the
emulsion.
The aqueous component of the emulsion may be composed
simply of water or may contain nitrogenous compounds such
as urea or ammonia.
The hydrocarbon component is preferably composed of
bitumen, vacuum residue, or asphalt or a mixture thereof
where the individual components of the hydrocarbon
emulsion may vary greatly in proportion.
The oil in water emulsion is injected into the
secondary combustion region of the furnace above the primary
combustion zone in a manner that creates oil in water
bilayered droplets with an external aqueous layer of water
alone or in combination with urea, or ammonia and an inner
hydrocarbon layer of bitumen, vacuum residue or asphalt or
mixture thereof.
It is preferable that the droplets are evenly
distributed throughout the input stream and not broken
when the emulsion passes through the atomizer or injector
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into the furnace. The emulsion droplets are sized (Sauter
Mean Diameter (SMD) by the atomizer/injector, so that the
jet penetration and evaporation rate allow for the
formation of localized fuel rich contrary currents.
In the localized fuel rich contrary currents created in
the furnace by the carefully adjusted injection of the
reburn fuel into the secondary combustion region, the
droplets provide secondary atomization (micro-explosions)
as the liquid aqueous outer droplet layer vaporizes to
steam and releases the smaller hydrocarbon droplets which
create localized fuel rich contrary currents.
It is preferable to provide injectors that are in
several planes of the furnace to cover a range of regions in
the furnace.
As the NOX emissions from the primary combustion zone
passes through the currents rich in reburn fuel in the
reburn zone the NOX are reduced to N2, HCN, and other
reduced nitrogen entities.
The use of the reburn fuel disclosed herein and the
process of minimizing NOX emissions solves many of the
existing problems associated with present systems and
lowers the installation and maintenance costs of NOX
emission control systems.
Other objects and advantages of this application,
method and apparatus invention will become apparent from a
description of certain preferred embodiments shown in the
attached figures.
BRIEF DESCRIPTION OF THE FIGURES
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Figure 1 is a conceptual diagram of the contrary
current local cloud NOX reduction process in accordance
with the present invention.
Figure 2 is a process flow diagram, which shows the
fuel handling and emulsion making process of the reburn
fuel for delivery to the atomizers/injectors.
Figure 3 is an example of a dual fluid
atomizer/injector using either steam or sour solution gas
as an atomizing fluid and the resultant primary and
secondary atomization process used to both set up the
localized fuel rich contrary currents and introduce the
fixed reduced nitrogen agent in accordance with the
present invention.
Figure 4 is a diagram showing one embodiment of the
fuel injector delivery system of the present invention.
Figures 5 & 6 are diagrams of a utility boiler and
Once Through Steam Generator furnace to which injectors
have been added in accordance with the present invention.
DESCRIPTION OF THE PREFERRED EMBODIMENTS
NOX components in the combustion gases from a furnace
are reduced by injecting a bitumen containing aqueous
emulsion into the flue gas of a furnace downstream of the
primary combustion chamber and combusted in an oxygen poor
reducing environment to remove a significant portion of
the NOX components in the combustion gases.
As used herein "sour gas solution" means natural gas
that is not refined and often contains species such as
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hydrogen sulfide (H2S) in the 2000PPM range.
As used herein, "atmospheric tower bottoms" (ATB) or
straight run residue, is the byproduct that remains and
reflects the fraction or cut of the refining distillation
curve representing products with a boiling temperature
>800 F (>426.7 C).
As used herein, "vacuum residue" means the fraction
that remains after distillation of bitumen or crude oil
under either atmospheric (ATB or Atmospheric Tower Bottom)
or vacuum (VTB or Vacuum Tower Bottom) conditions that
contains fewer volatiles. Straight run residue or ATB is a
byproduct that remains and reflects the fraction or cut of
the refining curve representing products with a boiling
temperature greater than or equal to 800 F (426.7 C). The
typical application of this bottom product (VTB) is feed to
an asphalt plant, a thermal cracker, a coker, or as a
blending component for residual fuel (#6 HFO).
These bottom fractions or high boiling residues are
also used as asphalt or residual fuel oil (#6 HFO). Asphalt
is one of two available alternatives the refiner or
upgrading process may consider for these bottom residues,
depending upon the quality of the bitumen and the available
market.
The asphaltene concentration determines the quality of
the asphalt. Asphaltenes are very complex molecular
substances found naturally in neat bitumen, which impart a
high viscosity to the residue appearing solid at room
temperature. Asphaltenes consist of polyaromatic compounds
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with high carbon-to-hydrogen ratios (-1:1.2 depending on
source) defined operationally as the n-heptane insoluble,
toluene soluble component of carbonaceous material, such as
crude oil or bitumen.
As bitumen is processed, the asphaltene concentration
increases. A more comprehensive technical definition for
asphaltenes is contained in ASTM test method D 6560.
As used herein, "Solvent De-Asphalter" (SDA) is the
next step along the refining process, which operates at an
even higher temperature to handle an even more viscous
product. The SDA process uses a hydrocarbon solvent
tailored to ensure the most economical de-asphalting
design. Propane solvent is typical for the low-de-asphalted
oil or a heavier residue or bitumen. Designs have been
developed to produce a maximum yield of de-asphalted oil
and minimum yield of asphalt, the latter having a viscosity
range of 60,000 cp at 530 F (276.7 C) with a very high
concentration of asphaltene.
As used herein, "bitumen" means a mixture of highly
viscous primarily highly condensed polycyclic aromatic
hydrocarbons. Naturally occurring or crude bitumen is a
sticky, tar-like form of petroleum. Refined bitumen is
obtained by fractional distillation of crude oil. It is the
heaviest fraction and the one with the highest boiling
point, boiling at 525 C (977 F). Most bitumens contain
sulfur and several heavy metals such as nickel, vanadium,
lead, chromium, mercury and also arsenic, selenium, and
other toxic elements.
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Naturally occurring crude bitumen is the prime feed
stock for petroleum production from oil sands currently
under development in Alberta, Canada. Canada has most of
the world's supply of natural bitumen. The Athabasca oil
sands is the largest bitumen deposit in Canada and the only
one accessible to surface mining, although recent
technological breakthroughs have resulted in deeper
deposits becoming producible by in-situ methods.
As used herein "neat bitumen" is a product extracted
from oil sands (typically using the SAGD or CSS process),
is very viscous and is also referred to as non-
conventional oil or crude bitumen to distinguish it from
the freer-flowing hydrocarbon mixtures.
As used herein "burnout air" or "overfire air" means
the air introduced to the furnace downstream of the reburn
zone to complete combustion in a burnout zone downstream of
the reburn zone
Emulsion
The fuel utilized in all embodiments of the invention
comprises an emulsion of a hydrocarbon and water.
Depending of the relative quantities of each present, the
emulsion may be an oil in water emulsion or a water in
oil emulsion. The two types of emulsions function
differently in the instant process.
Where the emulsion is a hydrocarbon in water emulsion
the hydrocarbon component may itself be an emulsion of
varying composition in the aqueous component of the
emulsion.
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The droplet size is an important characteristic and
may range in diameter from 60 to 300 micrometer or larger
encasing 5 to 30 micrometers of inner droplet, preferably
from 60 to 300 micrometer encasing 5 to 20 micrometers of
inner droplet.
Aqueous Component
The aqueous component of the emulsion may be composed
simply of water or may contain nitrogenous compounds such
as urea or ammonia.
Where the emulsion is enhanced with a fixed nitrogen
reagent, the instant process will allow the water to
volatilize first and result in the process chemistry to
take place in the fuel rich clouds (local sub-
stoichiometric air to fuel ratios) created by the small
droplets of hydrocarbons from the inner bilayer of the
fuel droplets released by the secondary atomization
process.
The emulsion comprises an aqueous phase comprising
from 1% to 32% of the total volume (1 to 43% by weight) of
the droplet, preferably 20% to 32% by volume (30 to 43% by
weight), most preferably 15% to 25% by volume (20 to 34% by
weight).
The oil in water emulsions usable comprise 5 to 25,
preferably 5 to 20 micron size hydrocarbon droplets (SMD) in
larger (80 to 300 micron) water droplets. The size of the
hydrocarbon droplets which form the center portion of the
water droplets is determined by the process by which the
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emulsion is formed and by the micro explosions of the
vaporized aqueous surface of the droplets that serves to
disperse the hydrocarbons. The injector and/or atomizer is
the delivery system that distributes the 80 to 300 micron
droplets of the oil in water emulsion to the furnace
(primary atomization).
The water in oil emulsions usable comprise 80 to 300
micron size hydrocarbon droplets (SMD) established by the
injector and/or atomizer (primary atomization) with the size
of the smaller water droplets encompassed within the droplet
determined by the emulsion process and are typically in the
range of 5 to 30 microns or larger dispersed in the oil
emulsion droplets.
In this process the micro explosions of the individual
droplets determine the hydrocarbon droplets size (secondary
atomization).
The percentage of water in oil in water emulsions is in
the range of about 10 to 32% with optimum percentage water
in the 20 to 30% range. The percentage of water in water in
oil emulsions is in the range of about 1 to 10% with the
optimum percentage water in the 5 to 8% range.
The emulsion can also be made from a urea solution or
aqueous ammonia solution where the normal stoichiometric
ratio (NSR) which defines the concentration of the solution
(amount of urea, etc.) based on the amount of NOX emissions
exiting the primary flame zone is between 1 and 3. An
example of the calculation using NH3 (17 molecular weight)
to NOX as N02 (46 molecular weight) is for NSR = 1:
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NH3 (tons) = [NOX (tons)] [17/46]
and for NSR = 1.5:
NH3 (tons) = [NOX (tons) ] [25.5/46]
The aqueous phase of the droplets provides a means of
control of the reaction temperature in the fuel rich zones,
which will improve the NOX removal.
Hydrocarbon Component
The hydrocarbon component is preferably composed of
bitumen, atmospheric residue, heavy fuel oil, vacuum
residue, asphalt, or solvent de-asphalter or a mixture
thereof where the individual components of the
hydrocarbon emulsion may vary greatly in proportion.
The amount of the hydrocarbon component in the
hydrocarbon emulsion is as follows:
Bitumen: 57 to 99%, preferably 60 to 85%, most
preferably 65 to 80% by weight.
Atmospheric residue: 57 to 99%, preferably 60 to 85%,
most preferably 65 to 80% by weight.
Heavy fuel oil: 57 to 99%, preferably 60 to 85%, most
preferably 65 to 80% by weight.
Vacuum Residue: 57 to 99%, preferably 60 to 85%, most
preferably 65 to 80% by weight.
Asphalt: 57 to 99%, preferably 60 to 85%, most
preferably 65 to 80% by weight.
Solvent de-asphalter: 57 to 99%, preferably 60 to 85%,
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most preferably 65 to 80% by weight.
The hydrocarbon emulsion of bitumen, atmospheric
residue, heavy fuel oil, vacuum residue, asphalt, or solvent
de-asphalter is produced by providing high shear to the
materials as shown in Figure 2. The mixture of hydrocarbons
forms an emulsion in which the bitumen, vacuum residue (VTB
and SDA), or asphalt droplets are small enough so that a
majority of them do not break or coalesce when the emulsion
is stored in a day tank or passes through the
atomizer/injector into the furnace.
Furnace Temperature
To reduce the NOX, the emulsion of water (only or fixed
nitrogen enhanced water) and hydrocarbon is introduced into
the boiler after the primary combustion zone in a region
where the temperature is in the range of about 2000 F to
2600 F or about 1100 C to 1427 C, as shown in Figure 1.
Preferably, the emulsion is injected into regions of
the furnace in which the flue gas temperature is between
1900 F (1038 C) and 2600 F (1427 C), preferably between
1900 F (1038 C) and 2350 F (1288 C), most preferably
between 1900 F (1038 C) and 2200 F (1205 C) .
The process is designed to allow the disclosed reburn
fuel to react with the oxygen in the reburn combustion
process and to burn out almost completely. The emulsion is
designed and produced so the aqueous phase is the continuous
phase and the hydrocarbon phase is dispersed in the
aqueous phase as very small droplets (SMD = 5 to 15
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micrometers).
In this manner the volatization of the hydrocarbons
present in the hydrocarbon phase is delayed while the water
volatilizes. The delay may be finely tuned to the type of
furnace and combustion conditions so as to achieve and
maintain a desired temperature in the secondary combustion,
region to maximize NOX removal consistent with the
maintenance of other suitable operating conditions. This
procedure results in the lowest possible emissions of NOXat
the lowest cost.
In general, it is preferred to operate reburn fuel at
temperatures that are as low as possible, while still being
able to complete the burnout of the reburn fuel. This
increases the NOX reduction potential directly proportional
to the decrease in equilibrium NOX as the temperature
decreases.
However, where the fuel is very economical it is
possible to overcome this temperature limitation by using
more reburn fuel. Where the reburn fuel emulsion contributes
and amount in the range of 8% to 20% of the total heat input
to the furnace, it is necessary to use a large amount of
completion air.
If no completion air is used and an amount of reburn
emulsion, in the range of 1% to 7.9% of the total heat input
is used it is only necessary to assure that the primary
furnace is sufficiently air rich to supply the oxygen for
burnout.
Where the emulsion is made from materials that are less
expensive than the base fuel, higher quantities of heat
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inputs of reburn fuel may be used to achieve higher NOx
reductions.
The temperature window of the presently described
process is much wider than other reburn and Selected Non-
Catalytic Reduction (SNCR) processes.
The temperature window is 19000F (1038 C) to 2600oF
(1427 C). The emulsion is from 5% to 32%, preferably 20 to
30% aqueous phase and adjustments can be made to
accommodate different furnaces or furnace conditions.
The emulsion is injected into fuel rich areas (sub-
stoichiometric conditions) of the furnace and the secondary
atomization and water volatization takes place in the
localized fuel rich regions.
The ratio of aqueous phase to hydrocarbon phase in
the droplets may be modified to provide an aqueous phase
within the range of 5% to 34% to further modify the very
local reburn temperature.
Amount of Reburn Fuel
In one embodiment, the heat input from these
emulsified fuels is between 1% and 20% of the total boiler
heat input. In a preferred embodiment, the heat input from
these emulsified fuels is between 2% and 7.9%. Most
preferably the heat input from these emulsified fuels is
between 5% and 7%.
The droplet has an outside diameter in the range of 60
to 300 microns or larger, preferably 80 to 300 micron, most
preferably 120 to 300 micron. The oleophilic inner droplet
layer has a diameter of from 5 to 25 micron, preferably 6
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to 20 micron, most preferably 6 to 15 micron droplets.
The reburn reaction takes place in the fuel rich
contrary currents of the furnace zone down stream of (see
attached figures for injection locations) the primary flame
zone.
Where the aqueous phase of the emulsion contains urea
or aqueous ammonia, an additional NOX reduction is obtained
from the secondary atomization characteristics of the
emulsion releasing the fixed reduced nitrogen agents in
the fuel rich contrary currents or the deep staged regions
of the primary flame zone prior to the introduction of
overfire air.
Although overfire air can be used in the instant
process the preferred method is not to use overfire air.
These agents improve the NOX reduction by reacting
with the NOX to form N2. The fact that this reagent
reaction takes place in a localized or deep staged
(localized fuel rich contrary currents) fuel rich
environments allows for the process to perform effectively
at a wider and higher temperature range (1900 F to 2600 F)
for peak reduction efficiency of the reagents in a localized
reducing environment.
This is the reason for not using overfire air in the
most preferred embodiment because driving the entire furnace
sub-stoichiometric (total reducing environment in the
furnace) causes rapid corrosion of the boiler tubes and tube
hanger metals in the boiler due to high temperature
accelerated vanadium corrosion attack.
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This is when compared to traditional SNCR which take
place in an oxidizing environment with a narrow temperature
window (1750 F +/- 50 F). These are bell curves and the wider
temperature range for the localized reducing environments
gives the NOx reduction process more flexibility and
improved NOx reduction efficiency without causing
accelerated corrosion.
The instantly disclosed method allows for lower NSR and
the least amount of ammonia slip. The most preferred
temperature range for this invention is 1900 F to 2200 F
where peak NOX reduction efficiency for localized reducing
environment is obtained with an NSR = 1 to 1.5.
CO burnout is achieved by the excess oxygen available
in the fuel gas from the primary flame zone, without the
need for a completion overfire air system (OFA) or in the
deep staged condition with the introduction of OFA.
Injection
The emulsion is introduced both as streams (jets) and
spray droplets, usually in combination to assure better
coverage.
Figure 3 shows an example of a single "Y" jet dual
fluid atomizer providing primary atomization using the
energy from the atomizer and secondary atomization from
the emulsion to both release the fixed nitrogen reagent and
create the fuel rich local cloud (contrary currents). In
addition, a low-pressure mechanical atomizer can be used to
inject the emulsion into the furnace. Preferred methods of
introducing the burnout fuel utilize either dual fluids
using sour solution gas or low pressure (100 to 250 PSI
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range) mechanical injectors. The most preferred injection
method utilizes low pressure (125 to 200 PSI range)
mechanical injectors.
Different sized jets and atomized drops can be used
depending upon the requirements of the specific furnace.
The droplet size utilized is boiler and site specific and
the determination of optimal sizing is well within the
competence of those skilled in the art to determine.
Atomizing Fluid
Sour solution gas is a preferred atomizing fluid in the
atomizers/injectors. Other atomizing fluids such as steam may
be used.
The ratio of sour solution gas or steam to emulsion
product in the atomizers/injectors is in the range of 0.05:1
to 0.5:1 atomizing fluid to emulsion product, preferably in
the range of 0.05:1 to 0.20:1, most preferably in the range
of 0.05:1 to 0.10:1 of sour solution gas or steam to the
emulsion (on a pound per pound basis of atomizing fluid to
fuel). In a highly preferred embodiment low pressure
mechanical injectors requiring no atomizing fluid are
utilized.
Chemistry
The chemistry of the process is complex and involves
over thirty (30) chemical reactions. For illustrative
purposes, the process can be represented by one (1) basic
equation which occurs in a localized reducing atmosphere at
a temperature in the range of about 1100 C and 1425 C:
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NOX + NH3 + H20 + H2 - N2 + H2
The kinetics involved in the reburn zone to reduce
NOX are complex. The chemical reactions involved in the
reburning process were first proposed by J.O.L. Wendt in
the late 1960's (Wendt et al, 1973) . The following
discussion, derived from a report published by the U.S.
Department of Energy (Farzan and Wessel, 1991), is based on
the concepts introduced in this work. The major chemical
reactions follow. In the presence of heat & 02 deficiency in
local clouds the reaction process shown in Equation 3.1.1-1
shows hydrocarbon radical formation in the reburn zone.
CH4 , CH3+ + H+ (hydrocarbon radicals) (3.1.1-1)
These hydrocarbon radicals are produced due to the
pyrolysis of the fuel in an oxygen-deficient, high
temperature environment. The hydrocarbon radicals then mix
with the combustion gases from the main combustion zone and
react with NO to form CN radicals, NH2 radicals, and other
stable products (Equations 3.1.1-2 to 3.1.1-4).
CH3+ + NO ~ HCN + H2O (3.1.1.2)
N2 + CH3+ NH2+ + HCN (3.1.1.3)
H + HCN CN+ + H2 (3.1.1.4)
The CN and NH2 radicals and other products can then
react with NO to form N2, thus completing the major NOX
reduction step (Equations 3.1.1-5 to 3.1.1-7)
NO + NH2+ , N2 + H20 (3.1.1.5)
NO + CN+ , N2 + CO (3.1.1.6)
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2N0 + 2 C0 , N2 + 2 C0 (3.1.1.7)
An oxygen-deficient (reducing atmosphere) environment
is critical to these reactions. If 02 levels are high, the
NO, reduction mechanism will not occur and other reactions
will predominate (Equations 3.1.1-8 and 3.1.1-9).
CN + 02 1 CO + NO (3.1.1-8)
NH2 + 02 - H20 + NO (3.1.1.9)
To complete the combustion process, the excess air
(02) from the primary flame zone is used to complete the
fuel burnout after the local reburn zones have reduced
the NOx emissions. Conversion of HCN and ammonia compounds
in the burnout zone may regenerate some of the decomposed
NO,, by the reactions.
Although some additional NOX may be formed in the
burnout zone through these reactions, the net effect of
the reburn process is to reduce significantly the total
quantity of NOX emitted by the boiler.
The bilayer emulsion is preferably introduced through
atomizing nozzles or injectors, which can handle the
bilayer emulsion without breaking it down, and through
jets for maximum penetration and optimum droplet size
distribution.
The atomizers can include internal mixing, "Y" jet,
and "F" jet dual fluid atomizers with a range of spray
angles, including cone shaped spray angles, flat sprays,
individual finger sprays and single jet sprays. These dual
fluid atomizers (see Figure 3 as example) can use various
atomizing fluids with either steam or sour solution gas as
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the preferred atomizing fluid and sour solution gas as the
most preferred atomizing fluid.
The ratio of atomizing fluid to emulsion product can
range from 0.05:1 to 0.5:1 preferably from 0.05:1 to
0.20:1, most preferably from 0.05:1 to 0.10:1.
Operating pressures may range from 20 PSIG to 150
PSIG, preferably from 75 to 125, most preferably from 100
to 125 for dual fluid injectors. The preferred injection
method utilizes either dual fluids using sour solution gas
or low pressure (100 to 250 PSI range) mechanical
injectors. The most preferred injection method utilizes low
pressure (125 to 200 PSI range) mechanical injectors.
Burnout Or Completion Air Is Used
In an embodiment of the invention where burnout or
completion air is used, reburn fuel droplets are delivered
to the total furnace reburn region.
Burnout or Completion Air Is Not Used
In an embodiment of the invention where no burnout air
is used, the reburn area, the area of the furnace where the
furnace atmosphere is a reducing atmosphere, is injected
with the reburn fuel without mixing any of the reburn fuel
into other areas of the furnace where the oxidizing
atmosphere is left unchanged.
Figure 4 shows an example of a multi-nozzle fuel
handling and delivery system to be used to inject the
emulsion products into the furnace at several furnace
planes, levels, and areas.
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In an embodiment where no burnout air is used and a
face fired or opposed fired utility boiler is used it is
preferred to establish where the lanes of reducing
mixtures are located and inject the reburn emulsion into
these lanes while maintaining oxidizing lanes between the
injection lanes.
The relative width of the lanes depends upon the
amount of oxygen in the initial combustion products, the
final amount of oxygen, and how much additional fuel will
be injected into the reducing lanes. The absolute widths
will be sufficient to allow almost complete volatilization
and combustion of the hydrocarbon reburn fuel in the
reducing zone. The evaporation of the urea and/or aqueous
ammonia, if present in the emulsion, takes place in these
reducing lanes, thus allowing for the fixed nitrogen reagent
to be activated in these reducing lanes.
Furnace Type
In an embodiment of the invention where a tangentially
fired utility boiler is used, it is preferred to introduce
streams of emulsion one above the other in each corner of the
furnace. Atomized streams maybe introduced with the jets to
assure complete coverage in the proper SMD range so the
secondary atomization process takes place in the reducing
atmosphere locations of the furnace. It is not necessary to
introduce the emulsion into every corner. The same general
arrangement of the bitumen, vacuum residue, or asphalt water
emulsion injection would be used with and without completion
air.
In an embodiment of the invention where a Cyclone
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furnace is utilized, the NOX's present are treated in the
furnace after the combustion gases have exited the
cyclones. A lane arrangement is best unless completion
air is used.
In an embodiment of the invention utilizing the SAGD or
CSS process or refinery furnace, where no burnout air is used
in a Once Through Steam Generator (OTSG), a package drum
boiler, a field erected industrial boiler/furnace or a
horizontal pass type "D" package boiler, it is preferred to
introduce streams of reburn fuel emulsion into lanes of
reducing mixtures established by the primary burner/atomizer
(fingers of fuel rich fuel), by injecting the emulsion into
these lanes and maintaining oxidizing lanes between these
lanes. The relative width of the lanes depends upon the
amount of oxygen in the initial combustion products, the
final amount of oxygen, and how much surplus fuel is to be in
the reducing lanes. The same general arrangement of reburn fuel
emulsion injection is used with or without completion air.
In an embodiment of the invention utilizing a
Circulating Fluidized Bed (CFB) boiler where no burnout air is
used, it is preferable to establish alternate lanes of
reducing mixtures exiting the Circulating Fluidized Bed, by
injecting the reburn fuel emulsion into these lanes and
maintaining oxidizing lanes between the injection lanes. The
relative width of the lanes depends upon the amount of oxygen
in the initial combustion products, the final amount of
oxygen, and how much surplus fuel is to be in the reducing
lanes. The same general arrangement of reburn fuel emulsion
injection is used with and without completion air.
Figures 5 & 6 show examples of the reburn injection
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without completion air in both a Once Through Steam Generator
and a face fired utility boiler.
The inventive process does not require carrier air,
steam, or re-circulated flue gas. The atomizing fluid is
preferably sour solution gas used at heat inputs ranging
from 0.35% to 2% of the total heat input of the boiler.
With this invention expected NOx reductions can range
from 25% to 65% of the total NOX exiting the primary flame
zone.
The foregoing specification describes certain presently
preferred embodiments of the inventive method but it should
be understood that the invention is not limited thereto but
may be variously embodied within the scope of the following
claims.
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