so2&so3 gas dew point
SO2, SO3 and Dewpoint
Early recognition of the impact of H2SO4 on dewpoint of flue gas has already been mentioned (Johnstone, 1929).Among the first research into the mechanisms involved was that conducted by the British Coal Utilization Research Association.For example, in 1949 Whittingham (1949), reporting on previous work (Taylor, 1942; Dooley and Whittingham, 1946; Whittingham, 1948), presented the relationship shown below in Fig. 1 of dewpoint vs. H2SO4 in dust-free flue gas containing various amounts of water.Dewpoint was determined by a dewpoint meter consisting of an internally air-cooled glass thimble containing two electrodes, one of which was also a thermocouple measuring the surface temperature of the thimble.A low-voltage DC potential was applied across the electrodes and as increasing airflow cooled the thimble condensation would form an electrical bridge.The thimble temperature at which current flow was first detected was taken as the dewpoint.Wet chemistry was used to measure SO2 and H2SO4.Concentrations of SO3 and H2SO4 can be considered equal in the presence of even slight amounts of moisture. Figure 1 thus shows that 50 to 100 ppm of SO3 can raise dewpoint by 50C to 80C.
Whittingham went on to demonstrate that oxidation of SO2 by atomic oxygen,
SO2 + O 
SO3
is a major formation mechanism for SO3. Addition of species such as H2, Pb(C2H5)4, and Fe(CO)5, more likely than SO2 to react with atomic O, indeed reduced SO3 formation and dewpoint.
Since, in the manufacture of H2SO4, ferric oxide (Fe2O3) was once used to catalyze SO2 to SO3, it was recognized that the large area of oxidized metal in a boiler might generate SO3 in the same way.This was shown to be true by Tolley (1948) using mild steel at 600튏.However, Crossley (1946) determined that sulphur-related corrosion was not a problem in British power boilers fired with high-sulphur coal, and Barkley et al. (1947) showed that the more fly ash, the less SO3 was present, suggesting that the former absorbed the latter.
Hedley (1962) undertook study of SO3 formation using a small furnace designed to produce a flame with a controlled mixing history.The fuel was kerosene with carbon disulphide added to raise sulphur content to about 2%.He found that:
- under sub-stoichiometric conditions no SO3 formed;
- with excess air SO3 formation in the flame reached 70 ppm, even though the flame temperature, as high as 1500 튏, could be expected to encourage breakdown of SO3 to SO2;
- under excess air conditions SO3 concentration rose sharply from the point of ignition, peaked at a point downstream equivalent to a residence time of 0.03 s, and then declined gradually.
Fig. 1
Variation of dewpoint with H2SO4 content gases having different water vapour content
Hedley concluded that the amount of SO3 formed depends more upon the availability of atomic oxygen than upon sulphur concentration and that formation of SO3 in the flame is substantially more important than subsequent formation by catalysis.
Further work on acid dewpoint by various researchers, conveniently summarized by Lisle and Sensenbaugh (1965), called into question the reliability of dewpoints as determined by dewpoint meter.M?ller (1959) had used thermodynamic relationships to calculate the dewpoints of flue gas with very low concentrations of sulphuric acid and these showed a different relationship from those obtained by dewpoint meter (see Figure 2 below).Lisle and Sensenbaugh measured SO3 and SO2 using apparatus developed by Goks?r and Ross (1962) in synthetic flue gas made up of nitrogen, oxygen, carbon dioxide and sulphur dioxide.Concentration of SO3 was varied by feeding known quantities of dilute H2SO4 into an evaporator in the flue gas stream.Then, by varying the temperature of the SO3 condenser and measuring SO3 captured vs. SO3 passing through the condenser, it was possible to establish the temperature at which a given concentration of SO3 saturated the flue gas i.e., the acid dewpoint.The results of this work, shown in Figure 3, confirm the accuracy of M?ller's calculations based on thermodynamic equilibrium.
Work at Battelle Memorial Institute by Levy and Merryman (1965) on combustion of H2S in a one-dimensional flame indicated that H2S is first oxidized to SO(H2S + O2 H2O + SO) then to SO2(SO + 1/2 O2 SO2).Then oxidation to SO3 may occur via atomic oxygen(SO2 + O SO3) or molecular oxygen(SO2 + — O2 SO3).Formation of SO3 was greatly enhanced by the presence of platinum as a catalyst, particularly at temperatures above 600 K.V2O5 and copper oxides were less effective as catalysts but still produced about 500 ppm SO3, far higher than normally encountered in conventional flames.
In a study of SO3 reduction by low excess air and a magnesium additive in a 185 MWe boiler fired with residual oil Reese et al. (1965) found that SO3 formation depended on boiler load as well as excess air level.For example, when operating with 2% excess oxygen and without additive, SO3 concentration at the air heater inlet was 56 ppm at 185 MWe output, 39 ppm at 110 MWe output, and 12 ppm at 55 MWe output.In all cases, SO3 concentration dropped as excess oxygen was reduced below 2%. The increase of SO3 with load may be due to the greater availability of atomic oxygen one might expect at the higher furnace temperatures that prevail at higher load, but the authors later found that SO3 concentration was very low e.g., 3 ppm at the furnace outlet but had increased ten-fold at the air heater inlet.This infers formation by catalysis involving the convection surfaces.
Fig. 2
Comparison of data on the relationship between acid dew and flue gas H2SO4 concentration
Fig. 3
Acid dewpoint as a function of H2SO4 concentration in flue gas
About the same time, extensive research was conducted at CANMET using a well-instrumented pilot-scale boiler. In one test program Lee et al., (1967) reported test results from two very high sulphur Eastern Canadian coals (6.3 and 7.3% S, dry basis) and Western Canadian lignite (containing 0.7% S, dry basis) which were pulverized fired in CANMET pilot-scale research boiler. Test conditions ranged from near stoichiometric to 8% oxygen in the flue gas. Figures 4 and 5 respectively show SO3 and acid dewpoint for coal with 6.3% S. Figure 6 shows the relationship of SO3 to acid dewpoint, compared with the calculated data of M?ller. Lee et al. (1967) concluded that when firing high sulphur coals, relationship among sulphur content, SO3 level, acid dewpoint and corrosion potential becomes unpredictable. This may be due to the effects of ash which ranged from 10 to 17%. However, SO3 and acid dewpoint consistently dropped to low values when excess air was reduced below 1% oxygen in the flue gas.
Subsequently the same CANMET team used the pilot-scale boiler to study SO3 formation in combustion of No.6 oil (Lee et al. 1969). SO3 levels in the flue gas were found to be anomalously low. The cause was traced to the role of soot. In the vicinity of the coal-walled furnace, any soot which forms is likely to be deposited on the walls and, being sticky and porous, becomes a condensation site for H2SO4 formed when chilling effect of the walls drop SO3 below the acid dewpoint.
The acid may condense on the soot before the soot deposits on the furnace walls but in either case the metal of the furnace walls is then subject to attack. As expected, firing with low excess air reduced acid dewpoint formation. More important, addition of MgO to the oil in a ratio of 1/1000 resulted in successful neutralization of the acid at any excess air.
This groundbreaking research at CANMET led to wide implementation of MgO injection technique in large power stations firing heavy fuels. As a result, utility power plants can operate safely, reliably and with significantly reduced operating and maintenance cost using high sulphur heavy oils.
Fig. 4
SO3 concentration plotted against oxygen in flue gas for Four Star coal
Fig. 5
Acid dewpoint temperature plotted against oxygen in the flue gas for Four Star coal
Fig. 6
Acid dewpoint temperature plotted against SO3 concentration in flue gas
It has already been stated that the role of fuel sulphur in wastage of steam generators was recognized and extensively researched in the latter half of the twentieth century.?Syrett (1994) claimed that in fossil-fuel-fired utility steam generators corrosion is responsible for 50% of forced outages and adds 10% to the cost of electricity.?Of course, sulphur is not the only agent. Compounds of oxygen, nitrogen, calcium, chlorine, sodium, potassium and vanadium may also play a role sometimes in very complex relationships.?This is particularly true of high-temperature corrosion, i.e., steam generator tubes operating at temperatures of 400튏 to 650튏, in the presence of molten ash and oxides.?Under these conditions even highly alloyed steels may suffer catastrophic corrosion.?In cold-end or low-temperature corrosion, i.e., at temperatures below acid dewpoint, H2SO4 formed from fuel sulphur is the primary agent although in some circumstances HCl and H2CO3 may play some role.?Vanadium can also play a significant role in high-temperature corrosion and is of interest to this literature review because it is a major constituent in the ash of residual oils.?Chlorine, another element with catastrophic potential for corrosion at elevated temperatures, is of great concern to combustion systems firing municipal waste because of the chlorine introduced via polyvinyl chloride.?However, chlorine is not a common contaminant of fuel oil and so is not discussed extensively here.