Process for controlling acid gas emissions in power plant flue gases

An in-furnace sorbent slurry injection process for the simultaneous control of SO.sub.2 and NO.sub.x from power plant flue gases is described. An aqueous slurry of limestone or dolomite-doped limestone and a nitrogenous progenitor compound is injected into the furnace at temperatures ranging between 900.degree. C. and 1350.degree. C. Under optimized operating conditions, with urea selected as the nitrogenous progenitor, about 80% of the SO.sub.2 and 90% of the NO.sub.x are simultaneously removed.

The invention relates to an integrated process for the simultaneous 
reduction of SO.sub.2 and NO.sub.x in combustion gases, particularly 
utility boiler and incinerator flue gases. The mixed oxides of nitrogen 
herein referred to as NO.sub.x include nitric oxide, nitrogen dioxide and 
nitrous oxide. 
In the electrical power system of many utilities, such as Ontario Hydro, a 
substantial portion of the electrical energy generated is produced in 
coal-burning plants. Such facilities provide an important element of 
flexibility in conjunction with hydraulic and nuclear generators, the 
importance of which increases during periods of peak demand and when 
demand exceeds the predicted level. However, combustion effluents and 
waste products from coal-burning stations are a source of acid gas 
pollutants, those of chief concern being sulphur dioxide and nitrogen 
oxides. 
There have been many efforts directed to the removal of nitric oxide from 
combustion effluents. NO is the oxide of nitrogen that tends to 
predominate in high temperature combustion waste gases and cannot readily 
be removed by conventional scrubbing techniques. 
U. S. Pat. No. 3,900,554 (Lyon) describes the selective reduction of NO in 
a combustion element by dosing the effluent stream with ammonia or ammonia 
precursors such as ammonium salts, and aqueous solutions thereof. 
Canadian patent No. 1,089,195 (Azubata et al.) describes a process for 
removing nitrogen oxides from a gas by adding a reducing agent selected 
from the group consisting of ammonia, an ammonium salt, an amine and an 
amide, and additionally hydrogen peroxide to the gas at a temperature in 
the range of 400.degree. C. to 1200.degree. C., thereby decomposing the 
nitrogen oxides to nitrogen gas and water. 
U. S. Pat. No. 4,208,386 (Arand) discloses a process for selectively 
reducing NO.sub.x in a combustion effluent containing NO.sub.x by 
contacting the effluent stream in the presence of oxygen with urea or urea 
solution at a temperature in the range of about 870 C to 1110 C. 
There is likewise a large body of prior art directed to the removal of 
sulphur oxides, chiefly SO.sub.2, from combustion effluents, based on 
various modes of introducing chemical additives such as calcium carbonate, 
magnesium carbonate, limestone, dolomite, and calcium hydroxide, which 
react with SO.sub.2 so as to cause sorption on these particulate materials 
at elevated temperatures. 
Some of the prior art relating to SO.sub.2 reduction is reviewed in U.S. 
Pat. No. 4,555,996 (Torbov), which itself discloses the spray injection of 
a slurry of calcium carbonate into a first zone outside the combustion 
zone of a conventional J-shaped gas furnace at temperatures above about 
l200.C and at an experimentally determined location in the furnace such 
that the sprayed composition is dried to particles in a cooler second 
zone, where sulphur dioxide is bound to the sorbent particles. The 
measurements disclosed in Torbov were, however, carried out not with coal 
but in a pilot scale test furnace fired by a mixture of natural gas plus 
hydrogen sulphide, intended to simulate the combustion of coal having a 
sulphur content of approximately 3%. 
To date, there have been no practical and efficient techniques for the 
simultaneous removal of both sulphur and nitrogen oxides from the exhaust 
gases formed by burning sulphur- and nitrogen-bearing fossil fuels and 
wastes in boilers or incinerators. A problem encountered in attempts to 
develop a truly integrated system is that some of the possible additives 
for the removal of NO.sub.x are chemically incompatible with the sorbents 
used to remove SO.sub.2. 
Further, even where the active agents for the separate NO.sub.x and 
SO.sub.2 removal processes do not actually interfere with each other, it 
is not necessarily the case that operating conditions optimal for the one 
pollutant removal reaction will also be best for the other. U.S. Pat. No. 
659,996 issued July 25, 1989 to Heap et al. discloses the sequential 
removal of NO.sub.x and SO.sub.x from a combustion effluent stream by 
first introducing an NO.sub.x -reducing agent into a fuel-rich, 
oxygen-deficient "gaseous decomposition zone" at a first temperature 
range, followed by introduction of the reacted gaseous mixture into an 
oxygen-rich "reaction zone" where an SO.sub.x -removal agent is introduced 
at a second temperature range. 
We have discovered that the simultaneous removal of both kinds of 
contaminant can be effected by using an aqueous slurry of a fine 
particulate calcium based sorbent containing a "compatible" NO.sub.x 
-removing additive which forms reactive radicals in the temperature 
"window" in which the sulphation reaction takes place. Many known 
additive compounds which react with NO.sub.x outside this temperature 
window, between about 900.degree. C. and about 1350.degree. C., are 
unsuitable for integrating the removal of both SO.sub.2 and NO.sub.x. 
It is accordingly an object of the present invention to provide an 
integrated process for simultaneously reducing the sulphur dioxide, nitric 
oxide and other acidic components from flue gases produced by the 
combustion of fossil fuels in combustion installations such as utility and 
industrial boilers and waste incinerators. 
According to the process of the invention, SO.sub.2 and NO.sub.x removal 
may be simultaneously effected by injecting an aqueous slurry of a fine 
particulate calcium based sorbent containing a selected compatible 
nitrogen-based additive through an atomizing nozzle into a coal-burning 
furnace at temperatures ranging from 900.degree. C. to 1350.degree. C., 
where the slurry is injected in the form of a spray of very fine droplets 
of a size up to about 150 .mu.m mass median diameter (MMD) which are well 
dispersed within the flue gas stream to ensure good distribution and 
intimate mixing of the sorbent-additive mixture with the flue gas. 
The slurry droplet size is "boiler-specific", in that the optimum size to 
ensure efficient transport of the reagents and their distribution and 
mixing with the flue gas to maximize reactivity will vary with the boiler 
type, dimensions and configuration. In the pilot scale coal-fired furnace 
installation described below, an optimum droplet size for the atomized 
aqueous slurry composition was in the range of 3-17 .mu.m MMD, but larger 
droplet sizes are required for full scale boilers. The optimum droplet 
size range may readily be arrived at by empirical testing or by 
computation of an optimal size range with the aid of physical models, 
whereby boiler dimensions, configuration, type and aerodynamics are 
coupled with the parameters of the particular spray nozzle used. 
Sorbent and additives are introduced into the furnace at stoichiometric 
ratios of between 1.5 and 3.0 moles of sorbent calcium per mole of 
SO.sub.2 and at least 1.5 moles of additive per mole of NO.sub.x. 
The technique prevents deactivation of the sorbent at the temperatures of 
injection and allows for sufficient residence time at favourable 
temperatures for the reaction between SO.sub.2 and sorbent and NO.sub.x 
and additive to be efficiently completed. With suitable additives, which 
may be referred to as "nitrogenous progenitors", the additive/NO.sub.x and 
sorbent/SO.sub.2 reactions proceed substantially independently and are 
subject to mutually compatible optimum operation conditions. 
Urea has been found to be a preferred nitrogenous progenitor additive. 
Optimal simultaneous capture of SO.sub.2 and NO.sub.x was achieved by 
adding urea to an aqueous slurry of sorbent and carrying out the process 
under conditions for the optimum capture of both pollutants. Under such 
optimized operating conditions, up to 83% of the SO.sub.2 and 90% of the 
NO.sub.x can be simultaneously removed from a typical flue gas stream. 
Another useful nitrogenous progenitor is ammonium carbonate. Data discussed 
below shows that under optimized operating conditions SO.sub.2 removal of 
up to 75% is achieved with simultaneous NO.sub.x removal up to about 85%. 
The combination of limestone slurry with ammonia as the nitrogenous 
progenitor was found to be rather less efficient for the simultaneous 
removal of sulphur and nitrogen oxides than either urea or ammonium 
carbonate, with maximum SO.sub.2 and NO.sub.x captures of 58% and 64%, 
respectively. Examples of other nitrogenous progenitors for use in the 
simultaneous removal of SO.sub.2 and NO.sub.x according to the process of 
the invention include ammonium salts other than carbonate, cyanuric acid, 
etc.

FIG. 1 is a schematic diagram representing sorbent slurry injection in a 
coal-fired furnace installation. Sorbent slurry containing dissolved 
additive is injected through nozzle 10 by a stream of air or steam. The 
injection is made into the combustion chamber at a location removed from 
burner zone 12, such that the injection temperature is between 900.degree. 
C. and 1350.degree. C. 
The injection mode illustrated in FIG. 1 is "crosscurrent", that is, the 
direction of injection is across the flow of flue gases, but nozzle 10 can 
alternatively be directed in the direction of flue gas flow (cocurrent) or 
against the flue gas flow (countercurrent) towards the higher temperature 
zone, with significantly differing results, as discussed below. 
The flue gases, carrying sorbent particles along, proceed through air 
heater 14 where some of the thermal energy of the hot flue gas is given up 
in a heat exchange process and used to heat air returned to the burner 
zone for further fuel combustion. The flue gas thence proceeds to an 
electrostatic precipitator (ESP) 16 or bag house filter for removal of 
solid waste components. The solid waste is composed of fly ash intimately 
mixed with reaction products, namely CaSO.sub.4 and unreacted sorbent, 
CaO. Although the process of the invention produces about twice as much 
solid waste as coal ash alone, little problem with efficient ESP 
collection of particulate is to be expected in practice, because of the 
lower resistivity of resulting ash, as compared with that produced by 
injection of dry sorbents. The cleaned flue gases are finally vented 
through stack 18. 
The physical and chemical processes which occur in the course of the 
process may be summarized as follows: 
The finely atomized slurry injected into the furnace loses its water to 
evaporation very rapidly and the sorbent is calcined into a porous, 
well-dispersed reactive calcine: CaCO.sub.3 .fwdarw.CaO+O.sub.2. Under 
favourable conditions of temperature and residence time, sulphur is 
captured by the calcine: CAO+SO.sub.2 +1/2O.sub.2 .fwdarw.CASO.sub.4. 
Proceeding along with the above reactions is the thermal generation of 
amine radicals from the additive, RNH.sub.x +2OH.fwdarw.2NH.sub.2 
+CO.sub.2 +H.sub.2 O, and capture and removal of NO by the NH.sub.2 
radicals: NO+NH.sub.2 .fwdarw.N.sub.2 +H.sub.2 O. The hydroxyl radicals OH 
in the first reaction are generated in the combustion of fossil fuel. 
In view of prior publications describing the effectiveness of ammonia or 
ammonia precursors as agents for the removal of NO.sub.x from gas streams, 
a number of such materials were investigated as potential slurry additives 
for an integrated system. These initial attempts invariably met with 
limited success, in that the NH.sub.3 /NO.sub.x reaction was found to be 
very much less efficient in the presence of calcium-based sorbents for 
SO.sub.2 in the temperature ranges investigated, for reasons that are not 
entirely clear. The dispersal of particulate sorbent in aqueous ammonia or 
ammonium carbonate solution was found to give rise to considerable ammonia 
"slippage" through the furnace at those temperatures. Not only was the 
efficiency of NO.sub.x removal thereby reduced, but vented NH.sub.3 could 
foul the boiler and is itself an atmospheric pollutant. 
Unlike certain NO.sub.x removal agents which were investigated, we have 
found that selected compatible additive/NO.sub.x and sorbent/SO.sub.2 
reactions are not subject to interfering side reactions and apparently 
proceed substantially independently. With such additives and with the 
slurry injection made in the proper temperature "window", the particular 
choice of calcium-based sorbent and its concentration in the slurry are 
important determinants of the efficiency of SO.sub.2 removal, but were not 
observed to have any significant effect on NO.sub.x removal, all other 
experimental parameters being equal. Likewise, the concentration of 
compatible additive in the aqueous slurry of sorbent, an important 
determinant for NO.sub.x removal, appears to have no significant effect on 
the degree of reduction of SO.sub.2 over the ranges investigated. 
As noted above, however, integration of SO.sub.2 and NO.sub.x removal 
requires that the respective decontaminating reactions be subject to 
mutually compatible optimum operating conditions. This we have found to be 
the case for the additive/limestone aqueous slurry in the process 
according to the present invention. 
Description of Combustion Apparatus and its Operation 
The coal-fired furnace installation used to obtain the experimental results 
discussed herein was Ontario Hydro's Combustion Research Facility (CRF) 
designed for a maximum coal feed rate of about 20kg/h US bituminous coal 
at a firing rate of 640 MJ/h. The furnace is a refractory-lined 
cylindrical chamber, fully equipped for monitoring gas and wall 
temperatures. There are multiple ports for flame observation and for 
insertion of solid sampling probes. The pulverized coal is delivered 
downdraft to the burner with the combustion air which can be electrically 
preheated to temperatures up to 350.degree. C. (662.degree. F.). Gas 
burners on each side of the coal burner are used to heat the furnace to 
operating temperatures before beginning to feed the coal. 
The coal burner is equipped with a vortex generator and four air vanes to 
assure good mixing and adequate residence time of the fuel-air mixture in 
the combustion zone. The combustion gases in the furnace are cooled by 
water and/or air circulating in a cylindrical Inconel jacket around the 
furnace. This cooling system is equipped with temperature sensors and flow 
meters to control furnace quenching rates. 
The combustion gases leaving the furnace are further cooled by a series of 
air-cooled heat exchangers prior to entering the resistivity probe housing 
and ESP. The ESP consists of a cubic stainless steel chamber, and is 
equipped with two sets of interchangeable cells. One set has an 11-plate 
electrode with 2.5 cm (1 in) spacing, the other a 5-plate electrode with 5 
cm (2 in) spacing. The design specific collection areas (SCA, m.sup.2 
/m.sup.3 /s) for the two sets of cells are 39 (0.2 ft.sup.2 /cfm) and 17 
(0.09 ft.sup.2 /cfm) respectively for baseline firing conditions using a 
high volatile US bituminous coal. 
The CRF instrumentation permits system temperatures, and flue gas 
compositions (O.sub.2, CO.sub.2, CO, SO.sub.2 and NO.sub.x) to be 
monitored continuously. Gas temperatures in the furnace were measured with 
a suction pyrometer and flame temperatures with an optical pyrometer. Flow 
rates and pressures are measured by flow meters and manometers. All 
measuring and monitoring systems are linked to a computerized data 
acquisition system. Particulate mass loading in the flue gas before and 
after the ESP is measured with an isokinetic sampling system and particle 
size distribution of fly ash and wastes are measured with a cascade 
impactor. In-situ resistivity is measured with a point-plane resistivity 
probe situated in the resistivity probe housing. 
The slurry injection system used in carrying out the process of the 
invention in the CRF experimental installation is shown in FIG. 2. The 
injection system consists of a positive displacement pump 20 which pumps L 
the slurry from a continuously stirred mixing tank 22 under a pressure of 
94 to 104 psig. Slurry recirculation and a static mixer 24 upstream of the 
furnace keep the fine sorbent particles in suspension and prevent 
settling. A small metering pump 26 delivers the slurry to the atomizer 
nozzle 10 through which fine droplets are injected into the flue gas 
stream. 
The structure of the atomizer nozzle used in the injection system of FIG. 2 
is shown in greater detail in FIG. 3. The slurry is injected into the 
middle of the furnace through this high pressure twin-fluid nozzle 10 (5, 
3 or 2 mm) with an internal mixing chamber 28. Operating pressures range 
between 40 and 70 psig. The stainless steel nozzle tip 10a (purchased from 
Turbotak Inc.) produces droplets of about 17 .mu.m MMD for a 5 mm nozzle 
tip, 6 .mu.m for a 3 mm nozzle tip and 3 .mu.m for a 2 mm nozzle tip. The 
nozzle is equipped with a cooling jacket 30 which is necessary to avoid 
drying of the slurry and deposition of particles in the nozzle. 
As illustrated schematically in FIG. 1, the aqueous slurry of sorbent and 
urea additive was injected into the middle region of the furnace, where a 
selected injection temperature of between about 900.degree. C. and about 
1400.degree. C. could be achieved. Slurry without added urea or aqueous 
urea solution alone were injected through nozzle 10 in preliminary 
experiments, to study the non-integrated SO.sub.2 and NO.sub.x removal 
processes, respectively. 
In-furnace Injection of Calcium based Sorbent Slurries 
The parameters affecting SO.sub.2 removal in the absence of nitrogenous 
progenitor additive were studied by injecting slurries of two different 
Ontario calcitic limestones and a dolomite to remove SO.sub.2 from flue 
gases while burning a 1.7% sulphur Eastern U.S. bituminous coal. Also 
evaluated was sorbent injection using two other coals: a 1.5% sulphur 
blend of Eastern U.S. and Western Canadian coals and a 2.8% sulphur Nova 
Scotia coal. A Nova Scotia Mosher limestone slurry was used to remove 
SO.sub.2 from the Nova Scotia coal. All results were obtained using the 
above-described Ontario Hydro Combustion Research Facility. 
Slurry droplet size was found to be an important parameter in determining 
the efficiency of SO.sub.2 removal by sorbent slurry injection. Fine 
droplets are desirable to provide high sorbent surface area of the Ca 
based sorbents and good distribution and mixing of the reagents with the 
flue gases. If the droplets are too fine, however, the penetration of 
sorbents into the furnace is inadequate and their mixing with the flue 
gases is poor, resulting in diminished SO.sub.2 removal. FIGS. 4a and 4b 
present the results of measurements made using the Turbotak nozzle and a 
40% aqueous slurry of finely pulverized Pt. Anne limestone at a molar 
ratio of Ca (from sorbent) to S (from the coal), "Ca/S", equal to 3.0, a 
slurry flow rate of 70 ml/min and an injection temperature of 1200.degree. 
C. Optimum droplet size was found to be about 5-7 .mu.m. The coal/sorbent 
types tested were U.S. coal with Pt. Anne limestone (open circle data 
points), a mixture of U.S. and Western Canadian coal with Pt. Anne 
limestone (diamonds), Nova Scotia coal with Nova Scotia limestone 
(triangles) and U.S. coal with Beachville limestone (squares). 
Sulphur capture efficiency by limestone slurry injection was found to 
improve with increasing limestone porosity, as shown graphically in FIG. 
5. A 40% aqueous slurry of limestone with an approximate porosity of 50 
per cent achieved 70% SO.sub.2 removal at a Ca/S ratio of 3 (solid line) 
while under the same conditions (injection temperature 1200.degree. C., 
co-current injection mode and droplet MMD of 6 .mu.m) the limestone with a 
17% porosity captured only 55% of the SO.sub.2 line). The coal burnt in 
the pilot furnace installation was a U.S. coal with 1.7% sulphur content. 
Dolomite was found to be a more effective sorbent than limestone, for a 
given Ca/S ratio. At similar operating conditions, SO.sub.2 capture by 
dolomite with a porosity of 42% was 83%. However, the CaO content of 
dolomite is so low that its use alone as the sorbent would require the 
injection of too much slurry, increasing the dust loading effect to a 
point which could impair operation of the ESP. 
A number of limestone additives were tested as agents for enhancing 
desulphurization. The additives tested include dolomite, sodium hydroxide 
and hydrated lime, which were used to dope Pt. Anne limestone. A chosen 
fraction of the calcium from the limestone was replaced by an equivalent 
amount of the additive, thereby to maintain the same Ca/S stoichiometry as 
for the undoped (baseline) case. The experimental results are presented in 
the graphs of FIGS. 6a and 6b, from which it is apparent that the 
dolomite-doped Pt. Anne limestone was the most effective in enhancing 
sulphur capture. Injection temperature and mode and droplet size were the 
same as for the run without doping (FIG. 5). Plots of %SO.sub.2 removal 
and %Ca utilization are shown, the latter being a measure of the 
efficiency of the sorbent/SO.sub.2 reaction for a given sorbent 
composition and rate of sorbent addition. 
Replacing 10% of the calcium from the Pt. Anne limestone with dolomite 
improved SO.sub.2 capture from 70% to 80% and calcium utilization from 23% 
to 27% for a Ca to S ratio of 3.0, as seen in FIGS. 6a and 6b. At a ratio 
of 2.0, SO.sub.2 capture improved from 53 to 67% and Ca utilization from 
27 to 34%. The other aforementioned additives ranked in decreasing order 
of sulphur capture enhancement are sodium hydroxide and hydrated lime. 
Since dolomite is the most cost-effective of the additives and was found 
to perform better than the others in enhancing sulphur capture and in 
improving calcium utilization, dolomite-doped limestone would appear to be 
the sorbent of choice for slurry removal of SO.sub.2 emissions from 
utility boiler flue gases. 
Sulphur capture was found to decrease with decreasing Ca/S ratio, i.e. 
decreasing rate of addition of sorbent, for all coal/sorbent pairs tested, 
while sorbent utilization increased. The results shown in the graphs of 
FIGS. 7a and 7b were obtained by the co-current injection of a 40% aqueous 
slurry of sorbent using the Turbotak 3 mm nozzle to produce a droplet size 
of 6 .mu.m MMD. For the porous Pt. Anne limestone (PA), reduction of the 
Ca/S ratio from 3 to 1.5 resulted in a drop in SO.sub.2 capture from 70% 
to 50%. With dolomite, SO.sub.2 capture for the 3 and 1.5 Ca/S ratios were 
83% and 75%, respectively. In FIGS. 7a and 7b, the open circle data points 
relate to an injection temperature of 1200.degree. C. and the closed 
circles 1300.degree. C. "B", "US" "USWC", "D" and "NSC" stand for 
Beachville limestone, U.S. coal, U.S.-Western Canadian coal blend, 
dolomite and Nova Scotia coal, respectively. 
Other measurements on sorbent-only slurries showed sulphur capture to be a 
sensitive function of the injection mode and temperature at the injection 
site, FIGS. 8a and 8b. The data points in FIGS. 8a and 8b relate to 
specific combinations of coal and limestone having various Ca/S ratios as 
indicated in Table 1: 
TABLE 1 
______________________________________ 
COAL % S LIMESTONE Ca/S RATIO 
______________________________________ 
.cndot. 
U.S. 1.7 PT. ANNE 3.0 
U.S. 1.7 BEACHVILLE 3.0 
U.S.-WC 1.5 PT. ANNE 3.0 
.smallcircle. 
NOVA SCOTIA 2.8 NOVA SCOTIA 
3.2 
NOVA SCOTIA 2.8 PT. ANNE 3.0 
.quadrature. 
U.S. 1.7 DOLOMITE 1.5-3.0 
______________________________________ 
40% LIMESTONE SLURRY (PT ANNE AND BEACHVILLE) 
20% NOVA SCOTIA LIMESTONE SLURRY 
DROPLET SIZE -- 6 .mu.m MMD (TURBOTAK 3 mm NOZZLE) 
Nova Scotia limestone was injected at a Ca/S ratio of 2.2. Only the 
co-current injection mode was used with the dolomite and the U.S. coal. A 
nozzle with a 3 mm orifice, and in a few cases with a 5 mm orifice 
producing droplets of 6 .mu.m and 17 .mu.m MMD, respectively, were used. 
The SO.sub.2 content of the flue gas before and after injection was 
recorded, and the results are presented in the graphs of FIGS. 8a and 8b. 
As illustrated in these graphs, the optimum injection temperature for the 
cocurrent injection with all the coals and limestone tested was around 
1200.degree. C., while for the counter-current injection, around 1100 C. 
The lower optimum for the counter-current mode of injection arises from 
the fact that the slurry is in that mode injected toward the high 
temperature region of the furnace. Thus, the slurry injected at 
1200.degree. C. actually "sees" high temperatures where sintering and 
deadburning occurs and sulphur capture is less efficient. In either the 
counter-current or the co-current injection mode, sulphur capture was seen 
to drop by raising or lowering the injection temperature from the optimum. 
Optimum sulphur capture with all coals and limestone studies was 
significantly higher for the co-current injection than for counter-current 
injection, the highest SO.sub.2 capture of 83% being observed with 
dolomite. At temperatures below about 900.degree. C. or above about 
1350.degree. C., SO.sub.2 capture falls off considerably to unacceptably 
low levels for both injection modes and all sorbents investigated, as seen 
from the graphs of FIGS. 8a and 8b. 
In all of the separate and integrated runs whose results are presented 
herein, the furnace quenching rate was kept at 500.degree. C./s to 
simulate existing Ontario Hydro power plant units. One test was done in 
which the quenching rate was changed from 500.degree. C./s to 280.degree. 
C./s, thereby increasing the residence time for the slurry in the 
effective sulphation zone (900-1350.degree. C.) from 600 ms to 900 ms. No 
significant change in SO.sub.2 capture was observed, however, by contrast 
with prior known techniques for the in-furnace injection of dry limestone, 
for which an increase in residence time in the sulphation zone 
significantly improves sulphur capture. The reason for the relative 
insensitivity of the slurry injection is probably the fast reaction rate 
between limestone slurry and SO.sub.2 
In-furnace Injection of Aqueous Urea Solution 
Of the nitrogen-based additives tested for integration with SO.sub.2 
removal, urea appeared to be the most effective in reducing NO.sub.x 
concentrations in flue gases. It is soluble in the sorbent slurry, the 
injection temperatures for optimum SO.sub.2 and NO.sub.x removal coincide, 
and the SO.sub.2 and NO.sub.x capture reactions do not interfere with each 
other. In order to assess the potential for integration of urea as an 
additive to limestone slurry, a number of preliminary investigations were 
made of the parameters affecting NO.sub.x removal alone, by injecting urea 
solutions in the absence of calcium-based sorbents. 
As with the removal of SO.sub.2 by sorbent slurry alone, the mode of 
injection of urea solution into the furnace and the temperature at the 
injection location were found to be important determinants of NO.sub.x 
removal efficiency. Experimental results obtained are graphically 
illustrated in the plot of percentage NO.sub.x removal versus injection 
temperature given in FIG. 9, the solid graph lines relating to co-current 
injection and the two lower broken-line graphs to counter-current 
injection. A 13.5% aqueous solution of urea was injected through a 
Turbotak nozzle, the size of the droplets being 17 .mu.m MMD. The fuel 
burned was a 17%S U.S. Eastern bituminous coal. The urea solution was 
injected either co-currently or counter-currently to the gas flow at 
stoichiometric ratios of either 2 or 3, as indicated in the legend on the 
graphs. 
A comparison of these results with those discussed above in connection with 
FIG. 8a and 8b led to the hope that the co-current injection mode might 
prove suitable for integrating urea additive with sorbent slurry, since 
the injection temperature of 1100-1200.degree. C. for maximum NO.sub.x 
capture was the same as for maximum SO.sub.2 capture by the in-furnace 
injection of limestone slurry. At optimum temperature using co-current 
injection, NO.sub.x capture was seen to be 90% compared to less than 30% 
for the countercurrent mode. 
An important consideration for full scale application of an integrated 
process is that the attainment of 90% NO.sub.x capture afforded a 
temperature window of only about .+-.50.degree. C. If an 80% NO.sub.x 
capture is considered sufficient, that window widens to about 
.+-.150.degree. C. 
The removal of NO.sub.x by urea injection was also evaluated as a function 
of urea stoichiometry, i.e., the rate of addition of urea. The 
urea/NO.sub.x stoichiometric ratio was varied from 1 to 3 and variously 
injected into the furnace using 2 mm, 3 mm and 5 mm Turbotak nozzles 
producing droplets of size 3, 6 and 17 .mu.m MMD. 13.5% aqueous urea 
solution was injected at 1100 C. in the cocurrent mode. The fuel firing 
the burner was a 1.7% sulphur Eastern U.S. bituminous coal. The 
experimental results are set out in the graphs of FIGS. 10a and 10b, 
respectively showing the percentage NO.sub.x capture and the percentage 
utilization of urea as functions of the urea/NO.sub.x stoichiometric 
ratio. NO.sub.x capture by the urea stoichiometry of 3 and 1.5 for the 3 
mm nozzle were 90 and 80%, respectively and utilizations were 30 and 53%, 
respectively. 
Integrated SO.sub.2--NO.sub. x Removal with Urea Additive 
EXAMPLE 1 
Simultaneous capture of SO.sub.2 and NO.sub.x was undertaken by adding urea 
to an aqueous slurry of limestone and adjusting operating conditions for 
the optimum capture of each pollutant, on the basis of the above-described 
results for the separate sorbent/SO.sub.2 and urea/NO.sub.x processes. 
FIG. 11 is a plot of the measured SO.sub.2 and NO.sub.x percentage captured 
as a function of temperature for the following optimized operating 
conditions: 
a 40% aqueous solution of a porous Pt. Anne limestone slurry 
Ca/S ratio=3.0 
urea concentration of 13.5% in slurry 
urea/NO.sub.x ratio=2.0 
injection mode: co-current 
nozzle: Turbotak 3 mm, droplet size MMD, 6 .mu.m. 
The square data points relate to %NO.sub.x capture and the filled circles 
to %SO.sub.2 capture. 
The fuel was the same 1.7%S U.S. bituminous coal which was the subject of 
studies on the individual SO.sub.2 and NO.sub.x removal processes. The 
results show successful integration--the removal of up to 70% of the 
SO.sub.2 and 90% of the NO.sub.x if the limestone slurry additive is 
injected at 1200.degree. C..+-.50.degree. C. NO.sub.x capture drops very 
sharply at both higher and lower injection temperatures. SO.sub.2 capture 
has a much wider temperature window. As noted above, if a wider 
temperature window is required in order to ease full scale operation, up 
to 65-70% SO.sub.2 capture and 80-90% NO.sub.x capture is achievable in an 
operating window of 1130 to 1280.degree. C. 
EXAMPLE 2 
Simultaneous capture of SO.sub.2 and NO.sub.x was carried out using a 
different sorbent than in Example 1, namely 15% dolomite-doped limestone 
injected co-currently at 1200.degree. C. The rate of addition of sorbent 
to the combustion chamber, measured as the Ca/S ratio, was varied. In FIG. 
12, the percentage of SO.sub.2 capture (circular data points) and the 
percentage of NO.sub.x capture (square data points) are shown as functions 
of the Ca/S ratio and urea/NO.sub.x ratio. Under the aforesaid 
experimental conditions and at a Ca/S ratio of 3.0, simultaneous removal 
of about 90% of NO.sub.x and about 80% of SO.sub.2 were removed from the 
flue gas, representing a very satisfactory degree of decontamination in 
respect of both pollutants. 
EXAMPLE 3 
In order to compare the simultaneous removal of pollutants according to the 
integrated process of the invention with the separate removal of NO.sub.x 
and SO.sub.2 carried out under like experimental conditions, the two 
stoichiometric ratios in the integrated process were adjusted in concert. 
The results are set out in Table 2: 
TABLE 2 
______________________________________ 
Ca/S Urea/NO.sub.x 
% SO.sub.2 removal 
% NO.sub.x removal 
______________________________________ 
(a) 1.5 -- 62 -- 
(b) -- 1.5 -- 81 
(c) 1.5 1.5 59 75 
(a) 2.0 -- 67 -- 
(b) -- 2.0 -- 89 
(c) 2.0 2.0 67 88 
(a) 3.0 -- 80 -- 
(b) -- 3.0 -- 90, 91, 92 
(c) 3.0 3.0 78 90 
______________________________________ 
The indices "a", "b", and "c" to the left of the table refer in each case 
to injection of sorbent slurry alone, urea solution alone, and the 
integrated slurry, respectively. In each instance, the slurry was 
introduced by co-current injection through a Turbotak nozzle (6 .mu.m MMD 
droplet size), at an injection temperature of 1200.degree. C. The furnace 
was fired with 1.7% sulphur U.S. coal and the sorbent employed was the 15% 
dolomite-doped limestone of the previous example, which was noted to have 
produced the best overall results. 
Comparisons are made at Ca/S and urea/NO.sub.x stoichiometric ratios of 
1.5, 2.0 and 3.0. Within experimental error, the efficiency of NO.sub.x 
removal and SO.sub.2 removal in the integrated system are unchanged from 
their independent pollutant removal efficiencies. This demonstrated 
substantial independence of the sorbent/SO.sub.2 and urea/NO.sub.x 
reactions, in conjunction with mutually compatible optimum parameters such 
as injection temperature, injection mode etc., is the basis for the first 
genuinely integrated process for the simultaneous capture of both 
pollutants. 
EXAMPLE 4 
The graph of FIG. 13 includes the Example 1 data of FIG. 11 (solid curves) 
but shows in addition the data points obtained when a different nozzle 
("NRC") than the Turbotak was employed. Again, the square data points 
refer to NO.sub.x capture, the solid circles to SO.sub.2 capture. optimum 
injection temperature for both SO.sub.2 and NO.sub.x capture from about 
1200.degree. C. to about 1100.degree. C., owing to differences in spray 
characteristics between the two nozzles. The results are illustrative 
again, however, of the truly integrated character of the process of the 
invention, since SO.sub.2 and NO.sub.x removal may be simultaneously 
optimized using either nozzle. 
Integrated SO.sub.2 -NO.sub.x Removal with Ammonium Carbonate Additive 
The experimental data presented in the table below and graphically 
summarized in FIGS. 14a and 14b show that as a nitrogenous progenitor 
additive ammonium carbonate (AC) in an aqueous slurry of limestone is 
almost as efficient as urea for removing NO.sub.x from flue gases 
simultaneously with the removal of SO.sub.2. 
TABLE 3 
__________________________________________________________________________ 
SONOX PROCESS - SO.sub.2 -- NO.sub.x REMOVAL 
Sorbent-Additive 
Addition Rate, 
Inlet Concen. 
40% Aqueous 
Mole ppm Injection 
% Removal 
Slurry Ca/S 
AC/N 
SO.sub.2 
NO.sub.x 
Temperature 
SO.sub.2 
NO.sub.x 
__________________________________________________________________________ 
A. Effect of Temperature 
LS/D-AC 2.0 2.0 1100 
630 1350 55 
1250 47 18 
1200 50 32 
1150 55 54 
1100 56 70 
1025 50 85 
LS-AC 3.0 2.0 955 
495 1200 62 55 
1100 66 46 
975 62 65 
LS-AC 2.0 2.0 1155 
588 1200 70 71 
1.7 1.7 1200 64 63 
LS-A 3.0 3.0 1280 
598 1200 85 39 
1100 57 64 
975 59 53 
2.5 2.5 1200 69 18 
1100 54 55 
975 54 46 
B. Effect of Sorbent-Additive Addition Rate 
LS/D-AC 1.0 1.0 1100 
630 1100 38 43 
1.5 1.5 52 61 
2.0 2.0 61 75 
2.5 2.5 68 85 
3.0 3.0 74 87 
LS-A 3.0 3.0 1280 
598 1100 57 64 
2.5 2.5 54 55 
2.0 2.0 49 38 
1.5 1.5 45 30 
3.0 3.0 975 59 53 
2.5 2.5 54 46 
2.0 2.0 47 33 
1.5 1.5 46 31 
__________________________________________________________________________ 
LS/D = Pt. Anne Limestone doped with 10% dolomite 
AC = Ammonium carbonate 
LS = Pt. Anne Limestone 
A = Ammonia 
The data on simultaneous removal of SO.sub.2 and NO.sub.x with limestone 
slurry and ammonium carbonate under optimized operating conditions 
according to the invention indicate that with an injection temperature of 
about 1100.degree. C., a Ca/S ratio in the range of 2.5-3 and an 
AC/NO.sub.x ratio of between about 2 and 2.5, SO.sub.2 removal is up to 
75% and NO.sub.x removal is up to 85%. 
FIG. 14a shows the variation with injection temperature of SO.sub.2 removal 
(open circle data points) and NO.sub.x removal (close circle data points) 
at a fixed molar ratio of Ca/S equal to 2 and a fixed molar ratio of 
AC./NO.sub.x equal to 2, afforded using a 40% aqueous slurry of 
dolomite-doped Pt. Anne limestone with ammonium carbonate. 
Using the same reagents at a fixed injection temperature of 1100.degree. 
C., the variation of removal of the two pollutants with increasing Ca/S 
and AC/NO.sub.x mole ratios is illustrated in FIG. 14b. 
Integrated SO.sub.2 -NO.sub.x Removal with Ammonia Additive 
Graphical displays of data analogous to FIG. 14a and 14b for ammonium 
carbonate additive are given in FIGS. 15a and 15b with ammonia as the 
additive. A 40% aqueous slurry of Pt. Anne limestone with added ammonia 
was used. The variation of percentage removal of SO.sub.2 (open circles) 
and NO.sub.x (closed circles) with injection temperature is shown in the 
graph of FIG. 15a. The darker data lines relate to a reagent mole ratio of 
3.0 and the lighter data line to a reagent mole ratio of 2.5 for each of 
Ca/S and NH.sub.3 /NO.sub.x. In FIG. 15b, using the same sorbent and 
additive, the percentage removal of pollutants as a function of mole ratio 
is illustrated at two different fixed injection temperatures, 1100.degree. 
C. (dark line) and 975.degree. C. (light line). 
Under optimized operating conditions, SO.sub.2 and NO.sub.x captures of 
about 58% and 64%, respectively were obtained. Thus, limestone slurry with 
ammonia was found to be less efficient for removing sulphur and nitrogen 
oxides than either urea or ammonium carbonate, but still were reasonably 
efficient for the simultaneous removal of pollutants in the temperature 
window for sulphation of the calcium-based sorbent. 
In summary, the in-furnace injection of a calcium-based sorbent slurry with 
a compatible nitrogenous progenitor additive, according to the process of 
the invention has been found to afford a simple and efficient route to the 
simultaneous removal of SO.sub.2 and NO.sub.x from power plant and 
incinerator flue gas streams. The technique facilitates good distribution 
and mixing of reagents with the flue gas, prevents the deactivation of 
sorbent and allows sufficient residence time at favourable temperatures 
for the CaO/SO.sub.2 and additive/NO.sub.x reactions to be completed 
efficiently. The variables affecting acid gas capture by the process have 
been identified and optimized for maximum acid gas removal and sorbent 
utilization using various sorbents with different coals. 
The experimental examples are not intended to limit the scope of the 
present invention, but are illustrative only, and it will be obvious that 
certain changes and modifications may be practised within the scope of the 
appended claims. In particular, it will be appreciated that a wide range 
of nitrogen based compounds (nitrogenous progenitors) will be useful as 
additives in the integrated process of the invention, since many members 
of this family will produce reactive species, such as NH.sub.2 radicals, 
for the removal of NO.sub.x in the temperature window of between about 
900.degree. C. and about 1350.degree. C. in which the CaO/SO.sub.2 
reaction takes place, without chemically interfering with the sulphation 
reaction.