I
PETER D. MOSKOVITS
Esso Research ond Engineering Co., Linden, N. J.
-
Low-Temperature Boiler Corrosion and Deposits A literature Review
Boiler corrosion and deposits, due to sulfur-containing fuels, cause serious losses to the power generating industry. This review critically evaluates the literature on iesearch done to solve these problems R E S E A R C H on the nature of the reaction forming so3 in boilers, directed to finding a n inhibitor, has led to several proposed reaction mechanisms. In 1929, Johnstone (56) presented data from which he concluded that so3 in furnace gases does not originate from SO2 oxidation, but by the decomposition of sulfates in the coal. Later he stated (57) that the oxidation of SO2 to SO3 in flue gases is very small. Fuel oils contain no sulfates, but flue gases in oil-fired boilers contain SOa, so that some other mechanism must be operative. Subsequent views agree that SO3 in flue gases is formed by SO2 oxidation, but differ on whether this oxidation is homogeneous or heterogeneous. There are several views on the nature of the catalyst, in the case of heterogeneous oxidation. Whittingham and coworkers assumed that the uncatalyzed homogeneous gasphase reaction
so2
+0
+
SO3
(1)
is responsible, and have done considerable work (27, 39, 70, 92, 96, 97, 99, 700) to prove this point. They (27) studied the oxidation of SOz in flames and showed that the amount of so3 formed depended on the SO2 concentration, the nature of the gas burned, the position of the sampling point, the presence of organic flame inhibitors, and on the presence of nitric oxide. Increased SO1 concentrations resulted in decreased percentage conversion to so^. I t is known that SO2 and so3 act as inhibitors or chain breakers in the oxidation of sulfur vapor and it is possible that a similar role is played by SO2 here. Additions of nitric oxide (NO) a t the base of the flame also reduced the percentage conversion to SOa. These effects they explained in that both SO2 and NO trap atomic oxygen, the agent responsible for SO, formation. Thus, SO2 may be a self-inhibiting chain breaker in the reaction scheme, while atomic oxygen is the chain propagator. When the supply of town gas and SO2 was suddenly cut off and the flow of air continued, there was evidence that active chain centers having a life of the order
of seconds were formed in the flame and were capable of oxidizing the traces of SO2 still present in the gas zone. Nitric oxide and organic flame inhibitors are in competition with SO2 for any atomic oxygen present. Working with C 0 - 0 & 0 ~ mixtures in a heated tube, Whittingham (96) showed that SO, formation set in a t 600' C. and increased up to the ignition point; the contribution of the watercatalyzed oxidation of SO2 was negligible. Spectral studies (39) of flames containing sulfur oxides showed that the reaction of SO2 with atomic oxygen requires an activation energy. The formation of SO8 in coal gas flames depends on the presence of substances known to generate, or react with, atomic oxygen (700). The oxidation of SOZin the slow combustion of carbon monoxide, methane, methanol, hexane, and ether was also studied. In 1948, Whittingham (99) summarized his findings. With atomic oxygen, the following reactions form so3: SO2 SO2
+ 0 = SO3 + 81 kcal.
4-0 + M
= SO8
(2)
+M
(3) I n the termolecular reaction, M may be water vapor, which is very efficient in
Corrosion of economizers and air preheaters of boilers flred with sulfur-containing fuel has been the subject of much research work for the past three decades. Sulfur in the fuel is oxidized chiefly to sulfur dioxide (SOZ) during combustion. Some sulfur trioxide (SOJ i s also formed, and combines with water to form sulfuric acid, which condenses on and attacks low-temperalure boiler surfaces. These processes depend on a large number of variables, which do not exhibit simple correlations. In this article, selected papers are reviewed in an attempt to draw some general conclusions to reflect the present state of knowledge. Included are papers reporting on both coal- and fuel-oil flring, because SO8 formation and corrosion processes in both these types are similar.
assimilating excess energy. Increased so3 formation in oxygen-rich flames was observed in spite of the higher temperature of such flames, and may be attributed to additional atomic oxygen produced according to: CO
+ 0 = COZ (excited)
COZ(excited)
4-0
2
= Cot f 0
(4)
+ 0 (5)
Other S03-forming reactions are also possible :
+ + SOz OH + SO3 HOz + S 0 z = OH + SOs
H
0
(6)
2
(7)
T h e interaction of SO3 with atomic hydrogen was discussed (70), based on studies of the decomposition of sulfuric acid added to flames. With SO2 in reversed flames of air burning in CO (92), solid elementary sulfur was produced, but no HzSOa appeared in the combustion product condensate. When SOrcontaining air was passed through heated carbon tubes of varying length (97), the SO3 concentration increased very rapidly between 1346 and 1436' F. in short tubes, and this coincided with the appearance of a blue glow, possibly due to CO. I n longer tubes, SO3 produced during CO combustion in the first part of the tube underwent reduction at the surface of the remaining carbon according to : CSalid
+ SO8
CO
+ SO2 + 4 kcd.
(8)
Reactions in Boilers. All of Whittingham's work discussed above was carried out on a laboratory scale. Corbett (79) ran a statistically designed set of experiments on commercial boilers, covering wide ranges of the major operating variables. Statistical analysis of his data obtained with five different fuel oils (containing from 0.75 to 3.55% sulfur) showed no significant relation between dewpoint (measuring SO,) and the sulfur content of the oils, but the amount of SOZ was found t o be controlled by the amount of sulfur entering the boiler. The data further confirmed the earlier finding (27) that the degree of oxidation of SOZto SO8 is a parabolic function of the SO2 concentration in the flue gas. VOL. 51, NO. 10
OCTOBER 1959
1305
.A surface-catalyzed heterogeneous mechanism for the formation of so3 in boilers was proposed by Harlow ( 4 7 ) . Based on laboratory experiments and plant experience he concluded that in boilers so3 is formed by the ferric oxide-catalyzed heterogeneous oxidation of SO, on high-temperature superheater surfaces. Later he showed ( 1 8 ) that "surface combustion" was taking place a t the superheater tube surface, still further elevating the surface temperature, and that if the maximum surface temperature is moderated. no appreciable amount of acid is formed. Siliceous refractory also catalyzes SO1 oxidation, and the various catalytic effects cannot always be distinguished. LVhile Whittinghani and Harlow continued work on their respective theories, Widell (707) showed by thermodynamic and kinetic considerations of the SO2 oxidation reaction, that both types of reactions probably do take place in practice. The SO2-SO3 equilibrium does not favor so3 a t high temperatures. but the rate of formation of SO3 increases with increasing temperature. so that so3 may be present in excess of its equilibrium concentration. H e concluded that a major portion of the so3 is formed in the flame lvhile a minor portion is formed catalytically. also suggested by recent work ( 74). It was suggested (73) that if i t tvere not for vanadium, the SO? to so3 ratio obtained during combustion lvould be maintained throughout the boiler. \Yhile Corbett's results (79) do not support this view, it is possible that the vanadium-catalyzed oxidation of SO, also contributes slightly to the S o 3 content of flue gases. Rylands and Jenkinson (8s) thought that additional SO3 was formed on economizer tubes. The SO3 and moisture present in flue gases gradually attack the economizer tubes forming ferrous sulfate, which is osidized to ferric sulfate. The latter is a poLverful catalyst and participates in oxidizing some of the SO, from the flue gases to SO3 on the tube surface. Kecmtly \\'hittinsham agreed (91) that some of the acid may actually form by this secondary low-temperature process. Still later work ( 7 ) shows that in an initially clean oil-fired boiler, approximately equal amounts of SO3 are formed in the flame, furnace. and convection sections, while less so3 is formrd in the economizer and air heater sections. Other Reaction Mechanisms. Certain oxides of nitrogen are kno\vn to catalyze the oxidation of SO?, and if present in flue gases, they could contribute to the formation of sO3. Francis (37) suggested the following reactions possible during combustion :
+ so,* '/. N:! + SO3 KO? + S O ? * ?io+ NO
so3
1306
(9)
(10)
Theoretical studies of photochemical SO2 oxidation processes forming so3 have been extensively reported in the literature. Of late, Johnstone and coworkers have studied photochemical (47, 42) and other (58) SOa-forming mechanisms in connection with air pollution. Intense radiations are knolvn to abound in boilers. and if the requisitr intensities a t the proper \vave lengths exist in the combustion zone: some SO3 may form there photochemically. Hoivever: this formation and its inhibition have apparently not been reported. From these considerations, it appears that SO3 in boilers is formed by several processes simultaneously: sulfate decomposition ; homogeneous SO, oxidation by atomic oxygen: reactions catalyzed by ferric oxide and sulfate, and by other oxides such as those of silicon, vanadium, and nitrogen; and photochemical reactions. Therefore, probably no single inhibitor can eliminatta SO2 oxidation in boilers. Amount of Sulfur Trioxide Only a small portion of the sulfur in fuels is converted to SOBon combustion. For example (68), in the flue gas of a Bunker C oil containing 1 to '2%, sulfur. 92% of the total sulfur showed up as SOZ,ivhile only 2 7 , produced S03. Coal prepared for boiler use has a minimum sulfur content of about 0.8";, a maximum of some 4 to 5%, and an average of 1.5 to 2%. There are broadl!. three main forms of sulfur in coal as mined : pyritic (or sulfide]: organic (combined or otherwise held in the coal structure), and sulfatic (76). The sulfur content of heavy fuel oils used for firing industrial boilers covers approximately the same range, but the B.t.u. content of coal is generally only two thirds that of oil. Heavy residual fuel oils contain at least SOYA of their sulfur as thiophenes, and most of the balance as saturated closed-chain and open-chain sulfides. Traces of sulfones have been identified in fuel oils. The amount of SO2 in flue gases is influenced primarily by the amount of sulfur entering the boiler (79). but the amount of SO3 fails to sholv any relationship Lvith operational or other variables. I n laboratory experiments (27), the percentage conversion to so3 decreases as the concentration of SO2 increases. and it was found (79) that a t one sampling point on a boiler the degree of oxidation of SO, to SO, is a parabolic function of the SO2 concentration in the flue gas. Others (25) found a parabolic relation between the sulfur in the fuel and the so3 in the flue gas, so that SO3 increases with the fuel sulfur content, but less so a t higher concentrations. The amount of SO2 formed increased
INDUSTRIAL AND ENGINEERING CHEMISTRY
with flame temperature, but tended toward a constant value above 3182" I:. The SO3 concentration fell slightly as C o t concentration rose from 9 to 145;~;. I n Corbett's work ( 7 9 ) , the amount of SO3 showed no correlation \vith the sulfur content of the fuels. lvhich led him to conclude that the form in \vhich the sulfur is present in various oils may be significant. Rendle and LVilsdon (79) doped fuel oil Lvith carbon disulfide and petroleum disulfides. and found close agreement in the amount o f SOs formed. As thc carbon-sulfur bond in carbon disulfide is of a diffrrrnt t!-l)c' from that of petroleum disulfides. tile!. concluded that the form in which the sulfur is present in the oil is unimportant. Data (80) collected from numc'rous boilers fired by coal, oil, or gas containing from 1 to 55; sulfur. exhibited no correlation between the furl sulfur content and the deispoint (measuring SOs). Thus, the fuel sulfur content (type and amount), the flame temperature, and the flue gas SO2 and CO, concentrations may all have a bearing on the amount of S O 3 formed, but the relative importance of these factors is yet unpublished. At any rate, Corhett's conclusion (791, rhat "a rrduction in the sulphur content of the oil cannot be expected to give a corresponding reduction in the SO;{ content of the flue gases from its combustion.'' seems justified. Even more important, the Hue gas so3 content has little effect on the acid strength of condensate films ( 9 , 84. 86). which strength is one of the major variables controlling corrosion. It appears that as long as rhcre is a small aiiiount of SO3 in the flue pis. corrosion \vi11 tie cxpmienced. Thv numerical value of this "small amount" is not known. and will probably vary with conditions. but Rendle and \$Usdon have stated (7.0) that it would be necessary to reduce the fuel sulfur content to below 0.S?& by weight to reduce the deivpoint appreciably.
Dewpoint Meters to Measure SO:! One major problem in boiler corrosion research has been. and remains. the difficult!. of devising a reliable test for inscantancously deicrmining thc corrosion rate on boiler surfaces, and the rKect of remedial measures on this rate. Of these tests. deivpoint meters have received by far the most attention. T h e "acid de\vpoint" is the temperature a t which condensation begins upon cooling the system air-\\,ater--sulfiiric acid without change of pressurr. 'The electrical-conductivity--r)-pc de\vpoint meter is based on detecting a condensed film of acid, by measuring c h a n p in the electrical resistance bet\veen two electrodes set in a smooth surfacc. 'The surface may he cooled progressivcly and its temperature accurately fo1loisc.d.
The temperature a t which the resistance begins to break down is the "dewpoint." Johnstone (56) described the first dewpoint meter of this type in 1929. A 1952 review (78) cited some nine modifications of the instrument. Additional modifications (27, 37, 50) have since been described. Data on so3 concentration us. dewpoint were collected by several independent observers who took into account the water vapor content of the system also. Kear (60) plotted together such data by others (37, 82, 85, 700) and showed that there was considerable divergence among the various sets of data. More recently, Burnside, Marskell, and Miller (74) plotted their own data together with those of others (37, 56, 82, 85) and again showed divergence. That these discrepancies are not due to condensable components other than sulfuric acid and water was demonstrated by showing (37) that nitrogen, oxygen, carbon dioxide, sulfur dioxide, and oxides of nitrogen had no effect, and by showing (67, 82) that hydrochloric acid had no effect on the sulfuric acid dewpoint of flue gases. In 1954, Rylands and Jenkinson (82) raised some very serious objections against the dewpoint concept and against much that had been based on it. They pointed out that above the dewpoint there is acid deposition due to surface adsorption, a dangerous condition dewpoint measurements cannot indicate. Furthermore, dewpoint varies but slightly with acid content of the flue gas. Earlier, Taylor and Lewis (87) stated that the extent of dewpoint rise with fuel sulfur content is smaller than would be expected. An increase in fuel sulfur content from 1 to 4% increased the dewpoint from 239' to 288' F. Later, Rendle and Wilsdon (79) showed that in the range of 1 to 5% fuel sulfur content, the dewpoint rose only by about 7.2" F. for each 1% rise in sulfur content. Rylands and Jenkinson (82) also showed that the dewpoint is not a reliable measure of the acid content of the flue gas, which in turn is not necessarily a measure of the corrosive potential of the flue gas. Kear (65) indicated that once acid and corrosion products are present on boiler surfaces, corrosion continues even after the metal temperature is raised to or above the dewpoint, another dangerous condition dewpoint measurements cannot indicate. Further, virulent corrosive attack-due to hydrochloric acid-has been observed (64, 82) below the water dewpoint, a third dangerous condition dewpoint measurements do not indicate. (The water dewpoint is the temperature at which flue gases become saturated with water vapor on being cooled without change of pressure. The water dewpoint is below, and independent of, the acid dewpoint. Condensate formed at
and below the water dewpoint is practically free of sulfuric acid.) Against the electrical-conductivitytype dewpoint meter, Rylands and Jenkinson (82) raised the objection that acid tied up in the form of mist will not condense on its surface and thus defy detection. Also, they felt that sulfuric acid condensed dropwise, and the dewpoint was in effect the temperature a t which the dew drops would coalesce to form a conducting film. Flint (ibid.) contended, that film-wise condensation was taking place on the dewpoint meter surface, but no agreement was reached on this point. On the basis of the above objections, Rylands and Jenkinson concluded that the electrical-conductivitytype dewpoint meters are unreliable, giving untrustworthy results leading to misleading inferences. Whittingham (97) has stated later in 1954 that "Experience over the last few years has shown that the rate of acid build-up is a far more important factor than the actual dewpoint temperature in assessing the corrosive nature of combustion gases." Rate of Sulfuric Acid Build-Up
The rate of condensation as evidenced by the build-up of sulfuric acid films on boiler surfaces may be measured with a dewpoint meter in terms of microamperes per minute. It was suggested (27) that it might be possible to locate dewpoints by measuring the rate of acid build-up over a range of temperatures and extrapolating back to zero rate. Later others showed (74) that the current-temperature curve approaches the temperature axis asymptotically and that ". .it is quite impossible to locate the true dewpoint." Taylor (86) observed a peak in the rate of condensation at a surface temperature approximately 81" to 90' F. below the dewpoint. He found that the magnitude of the peak increased with increasing dewpoint. Taylor proposed a mechanism for condensation, in which the first stage in the transfer to the surface is the formation a t the dewpoint of mist particles containing sulfuric acid and water. For surface temperatures just below the dewpoint, only a small quantity of acid will diffuse to the wall under the influence of a slight temperature gradient. As the surface temperature is lowered, the mist particles in the gas grow at a rapid rate and produce the condensation peak rate. Below a certain critical surface temperature the particles are of such size that there will be a slow rate of diffusion to the surface; larger particles are swept away in the gas stream, resulting in a reduced rate of condensation. This seems to explain why up to a point condensation rate increases with decreasing temperature (temperature gradient-controlled diffusion), and after this point condensation rate decreases with decreasing tem-
.
perature (particle size is limiting diffusion). In summary, Taylor's results indicated that the rate of condensation increases with the temperature gradient between the bulk gas stream and the wall. I t also increases with the so3 partial pressure gradient between the bulk gas stream and the gas immediately overlying the condensate. Finally, Taylor found that an increased water vapor content of the gas stream reduces the rate of acid condensation in general. Because more water vapor produces a more dilute condensate which, in turn, presents a larger SO, partial pressure gradient favoring increased acid condensation rates, Rylands and Jenkinson (82) took exception to Taylor's lastnamed relationship and proved that an increased water vapor content of the bulk gas stream actually increased the rate of acid condensation. Later this was independently confirmed by Whittingham (94). The Boiler Availability Committee ( 9 ) recognized that there is a peak in acid condensation rate at a surface temperature of about 110' to 120' F. below the dewpoint and that this peak increased with increased dewpoint, but felt that this peak rate was independent of the water vapor content of the flue gases. In addition to temperature and so3 and water concentrations, the statistical analysis of Corbett's experiments (79) indicated other variables on which the rate of acid build-up seems to depend. As measured by the dewpoint meter, the rate of build-up is actually the difference between acid condensing and acid being removed in unit time. Statistically, the rate of build-up increased with increased boiler load and smoke number, and decreased with increased COS content. The class of fuel oils burned and the location of the sampling point on the boiler also exerted an influence on the rate of build-up. Sampling points differ with respect to gas velocity and sample dilution. The number of factors influencing the rate of build-up demonstrates its importance, but also point to the difficulty of correctly interpreting isolated rate of build-up readings (79). Data (80) collected from numerous boilers were plotted as the logarithm of the rate of build-up us. the dewpoint, but this correlation appears unconvincing. Also, the rate of build-up may be expected to be proportional to the acid concentration in the gas. However, in practice its value may vary by a factor of 1 to 100 from that expected. In model rotary air preheater experiments (go), the rate of acid deposition showed a maximum below the dewpoint, coinciding with a maximum corrosion rate. For gases having a dewpoint of 240' to 320' F., the peak rate of acid deposition and corrosion occurred at surface temperatures of 21 5 O to VOL. 51, NO. 10
OCTOBER 1959
1307
245" F. .4lso, fine particles of ash (52), particularly below 10 microns in diameter: affect the rate of acid condensation. Oiving to radiation, these particles may have a lower temperature than the flue gas and thus promote condensation onto their surfaces. This may be significant in the rate of solid deposits formation. This shows that the rate of acid buildup varies with temperature gradients, concentrations of SOB,HrO, and CO,, boiler load, flue gas velocity, smoke number, ash burden in the gas: the estent of mist formation lvhich ties up SO3, and possibly other factors. O n the other hand, the rate of acid build-up and the rate of corrosion generally increase together. I n some cases, the peak rate of acid build-up coincides with the corrosion peak rate.
Concentration of Condensed Acid It is well known that certain acid concentration ranges are far more corrosive than others, and the acid strength of condensate films on boiler surfaces may consequently be espected to esert considerable influence on the corrosion rate of such surfaces. As early as 1942, Taylor (85) published correlations of the sulfuric acid concentration in the condensate with flue gas water vapor content and dewpoint temperature. I n 1944, Rylands and Jenkinson ( 8 3 ) recognized the importance of the metal tube surface temperature, Lvhich they felt was the controlling factor. They postulated that S03-catalytically formed in the liquid film-on the tube surface ivill combine with such moisture as it requires to form sulfuric acid. An equilibrium acid concentration is thus established in the film Lvhich depends on the tube surface temperature. Flint ( 3 2 ) found that the concentration of acid condensing from flue gases depended on the temperature of the surface on which condensation took place, and on the sum of the partial pressures of H20 and SOZ. Taylor (86) found that the tempcrature of the condensing surface and the partial pressure of water vapor in the gas phase influenced the acid concentration of the condensate while the SO3 partial pressure did not. A change of the H P S Ocontent ~ of the gas phase from 0.007% to 0.07% by volume caused no change in the concentration of the condensate a t a selected surface temperature. The Boiler Availability Committee (!?) agreed that acid concentration depended on the water content of the gases and on the metal temperature, but not on the SO3 concentration in the gases. I n a subsequent paper, Rylands and Jenkinson (82) agreed that the partial pressure of water vapor does affect the acid strength of the condensate. This indicates that the acid concentration of condensate films depends on the
1 308
temperature of the metal surface and on the water content of the gas phase, but is apparently independent of the SO3 content. This latter conclusion may explain \vhy corrosion fails to correlate \villi flue gas SO3 content.
Extent of Corrosion The rsteiit cjf corrosion in boiler plants is controlled by several factors, including the rate of corrosion; the exposure time under various regimes-i.e., start-up. on-load, bankinq. shutdown; the nature and area of corrosionprone surfacrs; and the types and amounts (relative to the surfacrs) of corrosive agents present and available for attack. These controlling factors depend on a host of other factors. Sulfuric Acid Corrosion. Draxving on a large body of experience, the Boiler Availability Committee ( 9 ) concluded that high acid dewpoints \cerr measured in all boilers experiencing air heatrr corrosion and or deposits and, in all cases of low dewpoint. the boiler plant was free from these air heater troublrs, but noted that high delepoints were also measured in several boilers free from air heater trouble. Recently it \vas stated (80) that film build-up rate and corrosion rate increase together, and earlier it \vas shoivn experimentally (90) that peak rates of acid deposition coincide with corrosion peak rates, somekchere below the dewpoint. Other relations observed : corrosion peak rate a t metal temperatures 36" to 81 " F. below the dewpoint (33) or 50" to 100" F. below the dewpoint (89).or a t absolute nietal temperatures of 151" to 158' 1'. (91). The humidity of the combustion air was found to aff'cct corrosion significantly. Basically. all of these observations agree in that a peak rate of corrosion is obtained \vIicii h t h the gas and the metal are a t some temperature below the deicpoint. Other workers [67j,by contrast? obtained t\vo corrosion peak rates, \vhich coincided ivith the acid deicpoint and \rith the Lvater deivpoint, respectively, but these results may not be strictly comparable. Thurloic (89)found a general relationship brttveen the tceight of acid deposited and the Lceight of iron corroded and later showcd (SO) that the ratio between the rate of acid deposition (as SO,) and the rate of corrosion (as Fe) \cas about 1.72, indicating that all the acid was converted to FeSOI. i f h i t tingham (93) later found this ratio to vary from 6.2 to 8.0, and concluded that there was a considerable excess of acid even over that required to form ferric, rather than ferrous sulfate. Rylands and Jenkinson (84) showed that ferric sulfate solutions are very corrosive, while ferrous sulfate solutions are only slightly corrosive. Ferrous sulfate is remarkably stable in sulfuric acid solutions containing less than 507, acid,
INDUSTRIAL AND ENGINEERING CHEMISTRY
but at higher strengths the acid itself is an oxidizing agent and ferric sulfate appears as a corrosion product along with ferrous sulfate. A t the highest strengths, the ferric salt alonr is formed. Also. ferric sulfate is a po~cerfulcatalyst in oxidizing SO, to SO3 (&?I. Rylands and Jenkinson ( 8 I ) rcI)oi,ted t\vo peak rorrosion rates obtained by varying acid concrntration. O n e peak was obtained xcith a rather dilute. acid, the other \vith a rather concrntrated acid. The trough fcol,Liicd 1) t!ic plot of acid concentration i ~ s . metal Icc'ight loss bet\vcrn these t\vo l x a k riitcs corresponds to the acid co:icentration range of 50 to 805,. Bclo\c and above this range con-osion p u k s apprar, alrhough both the exact acid concenrratiuns corresponding to the 1jcaks. and tlic c'sact values of thr peaks \vi11 vary froin inetal to metal, and also icith condition?;. I n 24-hourtests ( G , j j , i t i c d s I'oiuid tliat corrosion rate drops altc'r 8 hotirs. As would be expected, corrosion continued even after the metal \vas raised above the deivpoint, once corrosion products \cere present on the surface. It was noted (97) that peak corrosion ratescoinciding with peak acid build-up rates-ivere observed at 11.5 to 12.5y0 CO? content of [he flue gas, and that removal of 905% of the dust burden from the flue gas increased corrosion fivefold. Intermittent boiler opration and transition from one regime to another doubtlrssly influence corrosion ~)rocesses in a complex manner. Other Corrosive Agents. The corrosive effect of sulfurous acid has been assumed negligible compared to that of sulfuric acid, but laboratory experiments ( 8 - 2 ) showed tliat o n 24 hours' e x p ~ s u at r ~ GO" F., a 59; sulftlrous acid solution corroded 25 times as much steel and four times as much cabt iron as did a 5';: sulfuric acid solution. The "cold end corrosion" encountered coinmonly at the \cater inlet o f economizers and at the air inlet of prelicaters \vas attributed mostly to the action of sulfurous acid. The corrosive action of dilute sulfurous acid solutions during lighting-up%banking, and idling periods of the boiler \cas also noted (97). Although fuel oils do not contain chlorine, as coals do, sra-water contamination produces stable sea \cateroil emulsions Lchich may liberate hydrochloric acid on combustion. Brlotc the bvater dewpoint temperature ( 8 2 ) SUIfuric and hydrochloric acids can coexist in the condensate. At 80" F., some 85% of the hydrochloric acid present in the gas stream appears in the condensate, and may cause virulent attack, Studies (67, 6J) on the corrosive nature of combustion gases containing hydrochloric acid in addition to SO, demonstrated that a t and near ambient temperatures hydrochloric acid solutions are extremely corrosive.
Small but definite amounts of corrosion have been identified as due to nitric acid, the attack of which becomes more important as that of sulfur compounds diminishes. However, nitrogen oxides can reduce the amount of sulfur trioxide and corrosion by the latter (60). The literature on low-temperature corrosion by combustion products has been reviewed extensively (46, 60, 76, 97). Various aspects of marine boiler corrosion have been discussed also (43). Another review (72) discusses the literature on the behavior of sulfur oxides in boiler systems. Annotated bibliographies of papers on boiler plant corrosion and fouling have been published (70, 77).
Extent of Solid Deposits In addition to corrosion, acid deposition leads to the formation of deposits. In 1944, Rylands and Jenkinson (83) offered an explanation for the buildup of solid deposits on the economizers of coal-fired boilers. After a n acid film has formed on the tube surfaces, fly ash will adhere to the film. The alumina the ash contains dissolves and forms aluminum sulfate which is thrown out of solution onto the surface of the deposit. There it is suddenly subjected to the heat of the flue gases; it swells up, becomes glutinous, captures more fly ash, and finally hardens off. Stalagmitic formations follow naturally, with the deposit peaks growing toward the direction of the fly ash supply. I n these processes, ash temperature and acid strength of the film control the amount of alumina going into solution. More concentrated acid will attack more alumina but will hold less aluminum sulfate in solution. The role which corrosion products play in the formation of solid deposits and in further corrosion has also been considered (84). I t was found that a complex deposit of fly ash and other constituents that could prevent ferric sulfate from falling away affords no protection, for the corrosion continues underneath as evidenced by a Iayer of ferric sulfate adjacent to the metal even in cases where the original ferric sulfate is not detached. The nature of the deposits is determined by the relative concentration of volatile alkali salts and sulfur oxides released from the coal according to Whittingham (98). H e found that oxide smokes can reduce the stickiness of the acid sulfate layers on which deposit formation is based. According to the Boiler Availability Committee ( 8 ) ,deposits on economizers are formed from fly ash, condensates, and products of these. As a rule, the higher the phosphate content of the deposit, the lower the sulfur content, and vice versa. Air heater deposits occur a t the water dewpoint and a t the acid
dewpoint. Sodium and potassium combine more readily with SO8 than with SOz, and the products deposit as dry sulfate and sticky bisulfate on cooled surfaces. The proportions of potassium and sodium to so8 and SO2 seem to govern the amount of sulfate, bisulfate, and liquid acid deposited in the various temperature zones. In oil-fired plants (g), sulfatic deposits similar to those in coal-fired boilers commonly occur. Field tests ( 4 ) showed that some air preheater deposits contained over 30 elements. All deposits were partially water soluble, contained sulfates, and showed acidity. Deposits on the colder part of a n air preheater studied were in general thin, but a t the cold top area deposits readily built up in thickness. The greatest deposits on economizers and air heaters (52) occurred a t surface temperatures, from 235' to 275" F. High-temperature deposits on superheater tubes are reported (88) to contain much more sulfate than the coal ash, and are lower-melting. These melts hold fly ash and build up until stoppages occur. Tests showed that the sulfate resulted largely from the reaction of NaCl with SOZ, catalyzed by Fe203, which allowed the reaction to proceed a t temperatures as low as 572' F. The quantity of deposits formed from radioactive sulfur labeled SO8 was fairly constant over a wide range of temperatures and was not affected by the catalyst. It was concluded that under certain conditions, SO2 is the primary cause of sulfatic high-temperature deposits. Also, it was pointed out (36) that SO8 plays a much more important role in high-temperature corrosion than had generally been accepted.
Additives a s Remedial Measures Broadly, remedial measures involve either some change in boiler design or operation, or the addition of some substance to the fuel supply or to the flue gas stream. Additives to help prevent boiler corrosion may function by one or more of the following mechanisms: adsorb so3 physically; inhibit the formation of sea; and neutralize SOa by combining with it chemically. Some additives are known to function by a combination of these mechanisms. For example, zinc oxide adsorbs and then neutralizes it forming zinc sulfate. Adsorbents. The removal of soot and other combustion products from boiler tubes prevents corrosion (57). Kear and Whittingham (66) have studied the reactivity of coke with SO8, and concluded that the extent of SOa reduction increases with temperature in a very complex manner. Engel (28) reported that the addition of finely divided coal or coal ash lowers the dewpoint and reduces SO8 formation. I t had been observed long ago (57) that boilers fired with pulverized coal
so:,
are less affected than others. This has drawn attention to the role of fly ash and its constituents. Crossley, Poll, and Sweett (24) have studied the reduction of SO3 by flue dust constituents. They found that magnetite (FesOl) reduces sea, particularly above 932" F. Coke reduces so3 a t temperatures below the ignition point of coke. The remaining "white fly ash" fraction showed little reducing action. The addition of dust collected from electrostatic precipitators on pulverized fuel fired boilers (20) reduced the corrosive nature of flue gases materially. Unfiltered flue gas showed higher acidity than filtered flue gas, confirming that flue dust adsorbs SO3. Another class of adsorbents, called "smokes," includes artificially prepared suspensions of carbon, silicon monoxide, and zinc oxide. Carbon smokes (93) added a t 0.54 mg. per liter concentration to a flame containing o.O6y0so2 reduced the fraction of total sulfur appearing as SO, from 0.082 to 0.008. Also, as carbon smoke was added to an SOa-containing flue gas there appeared to be an initial increase in corrosivity, but as additions increased there was a substantial drop in the dewpoint and corrosive nature of the gases (62). Silicon monoxide (99) aerosol produced by heating various silicates with carbon above 2192' F. reduced the dewpoint of a flue gas. Similar results were achieved by spraying alkyl silicates into flames (95). T h e effect of zinc oxide smokes was studied in the laboratory (69). By spraying zinc acetate into the burner, controllable amounts of zinc oxide were produced in the flame. At first the zinc oxide smoke increased the dewpoint and the rate of acid build-up, but eventually a noncorrosive layer was deposited on cooled surfaces. Studies (20) of the effect of zinc oxide smokes on boilers showed that a t times additions of as little as 0.25% zinc by weight of the fuel burnt reduced the dewpoint from 310' to 250" F. After cessation of the smoke addition the dewpoint quickly rose to its original value, indicating that the action of the zinc was on the so3 rather than on catalytic surfaces. Flint, Lindsay, and Littlejohn (35) studied the effect of various smokes, firing five oils containing from 0.75 to 3.5y0 sulfur, giving dewpoints between 250' and 300' F. They tried a soda residue, a calcium residue, and a commercial zinc naphthenate; only the last greatly reduced the amount of sea. However, according to the Boiler Availability Committee (9),zinc oxide smokes are uneconomical for coal-fired boilers. Oxidation Inhibitors. Oxidation inhibitors for SO2 may exert their action by a variety of mechanisms. They may: Combine with atomic oxygen in competition with SO2 Catalyze the recombination of atomic oxygen into molecular oxygen VOL. 51, NO. IO
OCTOBER 1959
1309
Displace the reaction equilibrium in the disfavor of SOa Catalyze the decomposition of SOa Poison any SO2 oxidation catalyst that may be present or Act by a combination of some of the above mechanisms. However: present knowledge on the actual mechanism \\!hereby certain oxidation inhibitors act is limited. Carbon tetrachloride, pyridine. ethyl nitrate, ethyl alcohol. and benzene have been studied in the laboratory as flame inhibitors or "flame speed reducers" ( 2 7 ) . Iron pentacarbonyl and tetraethyllead added to SO*-containing flames eliminated SO3 formation completely ( 9 9 ) . Tin tetrachloride additions proved somewhat less effective. Coal tar bases sprayed into a town's gas flame reduced the rate of acid build-up and corrosion a t all surface temperatures below the dewpoint of 280' F. (63). Recirculation of a proportion of the flue gases Ivith the primary air has been claimed (76) to decrease the so, present in the final gases of a boiler. SOs Neutralizers. iimong solid SO, neutralizers, the most popular is apparently dolomite-calcium carbonate containing at least 30% magnesium carbonate. Dolomite combats high-temperature and low-temperature corrosion simultaneously. Huge and Piotrer 1533) found that a O.lycaddition of dolomite based on the fuel oil can eliminate corrosion damage. The dexvpoints \vere lowered from 342' to 302' F. a t the air preheatcr inlet, and from 309' to 284' F. a t the outlet. The larFer temperature drop across the preheater in the absence of dolomite indicated larger amounts of acid precipitation, while dolomite reduced this. Also, Lvith dolomite, the deposits on the preheater became lighter in weight and color. Dolomite was first added to the fuel, later injected into the flue gas by a n air jet, a t times just before the air preheater. Further work with dolomite has been reported in 1957 i.5, J5), Commercial preparations under the trade-mark Amber Desulfurol baize been claimed to reduce corrosion by 50 to i >Ci ,c in concentrations of one part per thousand, while simultaneously reducing smoke and soot formation and fuel consumption (29). Zaczek and Grindley (703) have presented data on Amber Desulfurol SSR 509 and SSR 113. The latter contains alkaline earth and other metals. I n a power plant it is said to have reduced the incidence of sulfur corrosion by joyc,the so3 content by about 657,. and the air heater deposits to such an extent that the boiler remained on load more than twice as long as without the additive. The nature of the deposits was reportedly modified also. These authors claimed that most remedial measures tried to date were impractical for one reason or another. Thus, operating a t reduced
-_
1 3 10
excess air may lead to soot formation. Coatings on endangered surfaces are subject to penetration. Nitrogenous organic bases lead to fouling. Flue gas scrubbing and fuel desulfurization are uneconomical. Ammonia, if introduced too near the stack, will mix poorly with flue gases and still permit corrosion to occur in patches; if introduced too far from the stack, the temperature is sufficiently high to decompose the ammonia, resulting in sticky deposits forming in the air preheaters. giving fouling and corrosion. T h e injection of ammonia has been recommended by Rendle and \Vilsdon (79) over all other remedial means they tried, including dolomite, magnesium and zinc naphthenates, magnesium soaps, magnesium oxide, poivdered zinc. silica, carbon, and nitrogenous materials. They found that when burning residual fuel oil containing 3.2 to 3.4'3 sulfur, the injection of 0.06y0 ammonia by lveight of the fuel into the combustion gases at about 572" F. was the most efficient and economical method for eliminating the acid deivpoint and for reducing the corrosion of exposed steel surfaces to a negligible level. Sulfur dioxide \vi11 not combine with ammonia above 302" F.. so injection of ammonia betiveen 11 1 2 ' and 302' F. \vi11 remove SO3 selectively. BetLveen 932" and 297' F.. the ammonium bisulfate formed is liquid and part of it will solidify on cooled surfaces, \vhile the remainder will be suspended and carried axcay Lvith the flue gases. 'The normal sulfate is solid below 662" F. and will tend to adhere to the molten bisulfate before this solidifies. Under normal running conditions. the authors claimed that the deposits \vi11 remain dry and corrosion should be negligible. T h e authors have patented (702) the injection of ammonia into the combustion zone. This method found application in Germany (3.5).
Other Remedial Measures The Boiler .Availability Committee ( 9 ) and others (38) have long advocated the adoption of pulverized-coal firing. The average SO, content of deposits is 42.2% in stoker-fired boilers, compared to 3.8% in pulverized coal firing (59). Auxiliary pulverized fuel firing materially diminishes the corrosive nature of flue gases from chain-grate-fired and retort-fired boilers alike (20). The auxiliary firing of several materials was studied by Barker and Corbett (3). They evaluated pulverized pitch, moderately high-volatile coal with partlyinert gases as carriers. and fuel oil and creosote pitch both with and without pulverized coal: on a chain-grate stoker coal-fired power-station boiler. They found that the auxiliary firing of a 3.37, sulfur heavy fuel oil with a 1.3y0sulfur coal, with and without auxiliary pulverized coal containing 1.3% sulfur.
INDUSTRIAL AND ENGINEERING CHEMISTRY
raised the dewpoint but reduced tht- rate of acid build-up and the corrosion potential of the flue gases. T h e Boiler .4vailability Cornmittee ( 8 ) has recommended for some time lancing and other cleaning of boiler surfaces. It has reported (9) that a conversion of air preheaters from counter- to parallel floiv has raised the minimum element plate temperaturr, reduced the rate of acid build-up. and improved availability consideratdy. It has also reported some cases \vherc auxiliary pulverized fuel firinq togethcr \vith flue gas recirculation has allrviated corrosion and deposit problrms. Among various methods tried. Rothernich and Parmakian ( S I ) found the usc o f recirculatrd air the most rfi'rctive method for preventing air prehrater corrosion and deposits. 'l'he installation of espendablr castiron auxiliary air preheaiers to wive as the cold end of expensive air preheatcrs has been reportrd ( 6 ) . .i few rows of expendable elements i n air preheaters. to be rene\vcd every fmv years, give addc-d rfficirncy that niore than outkveighs the cost of prriodic replacement (55). Harlow ( I S ) claimed that modrrating superheater surface temperatures reduces SO8 formation: but curren1 drsigns tend to still higher. not lower. superheat temperatures (55). Operating expt-rience with oil-fired boilers showed that hotter combustion chambers--i.e.. those containing feLver tubes and removing less heat I'rom the flame. especially near' the burners-cause less SO2 oxidation. Improved combustion due to increased rurbulencr: and operation a i lo\\rred combustion chamber loads also lessen the c~xidation of so2 I i o ) . %a and Grindley (703) have stated that operation with reduced excess air lo\vrrs SO, formation. corrosion. and louling. but adjustment is critical, and if ovc'rdone. soot and smoke emission result. Soot collects in the stack. adsorbs and conccntrates acid from the flue gasrs. and acidic particles so formcd may tir discharged intermittently Crom thc stack and deposited in the neighborhood. 'They also pointed to the importance ol correct oil atomization. Rylands and Jenkinson (S1) suggested that much of the sulfur in furls forms Lvith water vapor a very persistent acid mist Lvhich is carried through [he boiler without causing damage. 'l'hcy proposed the introduction of a "supercooled" surface into the boiler to inoculate the gas: initiate mist formation. and reduce the degree of supersaturation, bvhereby more mist bvould form and less acid would condense on boiler surfaces. This is "shock cooling '' There are other ways of inoculating flue gases, but they felt this to be best. On-load washing of corrosion-prone surfaces was first applied in 1923. and
after being abandoned in 1927, it has recently staged a comeback. Jenkinson (55) has described the method as it is now applied. Operating experience with on-load washing showed that the method is sound and may be developed to a high degree of perfection (54). Various corrosion resistant materials for air preheater construction have been evaluated by Barkley and coworkers ( 4 ) . They concluded that sulfate-forming metals cannot be used without corrosion and eventual plate failure. Others (87) have also evaluated some materials for air heater construction. The Boiler Availability Committee ( 9 ) stated that cast iron resisted corrosion better than mild steel, and Rylands and Jenkinson (84) gave the reasons why cast iron had these inherent properties which increased its resistance to corrosion over a wide range of conditions. Cast iron is also preferable to mild steel in air preheaters subject to frequent shutdowns. Regarding protective coatings, it has been noted (703) that although polytetrafluoroethylene has been applied with occasional success on the cooler parts of the plant, pinholes common in this type material lead to penetration. Coit (75) sought a coating to protect heat exchanger surfaces and compressor blades a t low temperatures, but found none suitable. Hinst (57) has recommended the oiling of tube surfaces after cleanipg. Coal tar bases introduced into the gas stream with the object of depositing a protective coating on steel surfaces have decreased corrosion below 243’ F., but have induced some corrosion above the dewpoint of 277’ F. (63). Harlow (47) has consistently advocated anticatalytic coatings. H e claimed that coatings of lime or fine pulverized ash on superheater tube surfaces prevent the formation of so3 and its consequences. Recently, he proposed the metallurgical or chemical treatment of tube surfaces to avoid their catalytic action (49). He recommended spraying the tubes with aluminum ethyl silicate or soda ash solution. The Boiler Availability Committee ( 9 ) acknowledged the inhibiting effect of coatings of lime, sodium carbonate, oil, and graphite compounds, but noted that their effect was temporary. Regarding the “immunity period” of new boilers ( 6 ) , apparently the consensus holds that there is none. Some deposits show a “flypaper effect,” where an initial deposit traps fly ash and then grows very rapidly. There have been cases where new boilers experienced failure and forced outage after only 1 or 2 weeks in service. Flue gas scrubbing may eliminate atmospheric pollution and may produce a salable by-product, in addition to remedying boiler corrosion and fouling.
The removal of the dust burden from flue gases may greatly decrease the rate of solid deposits build-up (52). Craxford, Poll, and Walker (23) reported that in scrubbing power plant flue gases with ammonia to remove sulfur oxides, 99% of the SO2 was recovered. Others (2) recovered SO2 by cooling the flue gases with water sprays and then neutralizing with ammonia. Of various methods investigated, Parker (74) found flue gas washing with an ammonia-containing solution most promising. T o prevent the corrosion of flue gas carbon dioxide recording instruments, SOz removal by absorption with sodium bicarbonate has been recommended (72). In a method (44) of precipitating heavy lime wastes with flue gas, the gas is subsequently scrubbed with soda ash to remove fly ash and corrosive sulfur compounds. In a patent (77), flue gases containing SOz and are scrubbed with a n Mg(0H)z suspension. The effluent is aerated to convert all M g S 0 , to MgS04. Then ammonia is injected to recover (NH4)?S04and M g ( W ) , , and the latter is recycled. A scrubbing tower is described (73) in which flue gases are treated with a Ca(OH)z suspenjion to remove up to 96% of the SOZ. Rees (78) noted that flue gas scrubbing tends to lower the gas temperature, and under certain weather conditions this may actually increase local pollution. H e described the scrubbing of flue gases with gas liquor to produce (NH&S04. Studies comparing various scrubbing processes have been made (30, 38, 7.4, and an extensive review of methods for removing sulfur oxides from flue gases has been published (22). In 1957 Zaczek and Grindley (703) stated that “there are no generally accepted methods of evaluating additives for corrosion prevention” and this problem is still among the largest in boilec corrosion research. Even though dewpoint meters leave much to be desired, these are still widely used at present (74, 79). Zaczek and Grindley (703) use flue inspection, flue gas SO, concentration measurements, iron corrosion measurements, and the measurement of changes in draft. There is a fourth-power relationship between deposit thickness and draft loss, so that the doubling of the thickness of the deposit increases draft loss 16 times (6). In addition to dewpoint meters, chemical methods for determining SO2 and SO, in flue gases have been described (7, 77) and used in developing a n automatic SO3 recording instrument (26). Flint and Lindsay (34) have shown that SOz oxidation in heated quartz sampling tubes is negligible; earlier such tubes had been blamed for erroneously high SO3 results obtained. Sampling tubes must be heated to avoid
so,
premature condensation or mist formation (78). Fletcher (37) described a sintered-glass filter capable of trapping SO3 mist, which would otherwise escape determination. The determination of SO? and SO, in flue gases has been extensively reviewed (78). However, sulfur oxides are not the only agents corroding boiler surfaces, and these surfaces are subject to corrosion during regimes other than full on-load. Also, fuel sulfur content does not correlate with flue gas SO3 content, and the latter has little bearing on the acid concentration of condensate films, and consequently on corrosion rates. Corrosion probes, on the other hand, are inherently exempt from these limitations and are capable of experiencing corrosion much like boiler surfaces do. These probes are usually in the form of steel tubes carrying hemispherical steel caps, equipped with cooling and temperature measuring devices, The iron loss as shown by the difference between initial and final probe weights appears to be a reliable measure of boiler corro;ion. Various corrosion probes (33, 75, 89). as well as corro:ion measuring apparatus for use with sulfur-containing gaseous fuel flue gases. have been described (77). Conclusions Sulfur trioxide formation in boilers appears to take place by several simultaneous processes. Therefore. probably no single inhibitor can cope entirely with SO, formation boilers. Additives to combat boiler corrosion include physical adsorbents for SO3, oxidation inhibitors for SOz, and chemical neutralizers for SO3. Other measures tried include changes in boiler design and operation. None of the additives or other measures have proven conclusively superior to all others to date. T h e extent of corrosion in boiler plants depends on exposure time, the nature, area, and disposition of corrosion-prone surfaces, the types and amounts of corrosive agents, and of course on corrosion rate. Corrosion rate, in turn, appears to depend on the rate of build-up and acid concentration of condensate films, and the metal temperature. The rate of acid build-up is very significant in controlling boiler corrosion, and depends on temperature gradients, concentrations of so3, HzO, and COz, boiler load, flue gas velocity, smoke and ash level, mist formation, and possibly other factors. Acid concentration in the condensate film is controlled by the metal surface temperature and by the flue gas water content, but not by the flue gas SO3 concentration; this explains why corrosion rates fail to correlate with flue gas so3 content. The amount of SO, formed in boilers shows no clear-cut relation to type and amount of sulfur in the VOL. 51, NO. IO
OCTOBER 1959
131 1
fuel, thus a reduction in fuel sulfur content does not give a corresponding reduction in flue gas SO3 content, particularly a t high sulfur levels. SO3 concentration measurement with electrical conductivity deivpoint meters has proven unreliable. Corrosion probes, recent tools in boiler corrosion research. simulate the behavior of and experience the conditions to which actual boiler surfaces are exposed; they may prove to be better tools than deiz point meters. Orher corrosive agents in boilers include sulfurous. hydrochloric. and nirric acid, and ferric sulfate which is produced by sulfuric acid corrosion of the boiler. Solid deposits form from fly ash, condensates, and products of these; in some cases SO? is the cause of hightemperature sulfatic deposits.
Acknowledgment Thanks are due to Esso Research and Engineering Co. for permission to publish this paper.
literature Cited (1) Anderson, D. R., hlanllk, F. P,, Combustion 29, No. 7, 59 (19581. (21 Andrianov, .A. P., Chertkov, B. -i,, Khtm. Prom. 1954. 394-401
(31 Barker, K., Cdrbett, P. F., J . Inst. Fuel 27,495-502 ( 1 9 5 4 1 . (4) Barkley. J. F., Karlsson. H., others, U. S. Bur. hlines Rept. Invest. h-0. 4996 (19531. ( 5 ) Bergan, P., Trk. C‘keblad 104, 81-7 (1957). ( 6 ) Berk, .A. A , , .\Iech. Eng. 75, 545-6 (1953). (7) Berk, A. A4., Burdick, L. R., U. S.
Bur. hfines Rept. Invest. No. 4618, (1950). (8) Boiler Availability Committee, London, Bull. MC/153,28 pp. (Nov. 19461. ( 9 ) Zbid., MC/234, 31 pp. (Feb. 1953). (10) Ibid.,MC/235, 24 pp. (Feb. 1953). (11) Zbid., MC/236, 27 pp. (Feb. 1953). (12) Bones: H . C., Instrument Practice 5 , 17-21 (1950) ; J . Iron Steel Inst. (London) 168, 441 (1951). (13) Borgars, D. J . (to Imperial Chemical Industries), Brit. Patent 680,868 (Oct.
15, 1952). (14) Burnside, W., h’farskell, FV.G., Miller, J. M., J.Inst. FueI 29,261-9 (1956). (15) Coit, R. L., Trans. Am. Soc. .llech. Engrs. 78,89-94 (1956). (16) Corbett, P. F., Bull. Brit. Coal Utilisation Research Assoc. 1 5 , 169-81 (1951). (17) Corbett, P. F.! J . Inst. F7tei 24, 247-51 (1951). (18) Corbett, P. F., Crane. I$-. hf., Bull. Brit. Coal C?ilisation Researrh Assoc. 16, 1-11 (1952). (19) Corbett, P. F., Fereday, F., J . Inst. Fuel 26, 92-106 (1953). (20) Corbett, P. F., Flint, D., Ibid.! 25, 410-17, 446 (1953). (21) Corbett, P. F., Flint, D., Littlejohn, R. F., Ibid., 25, 246-52 (1952). (22) Corbett, P. F., Littlejohn, R. F.,
Bull. Brit. Coal Utilisutton Research Assoc. 16, 437-44 (1952). (23) Craxford, S. R., Poll, A , , Walker, W. J. S., J . Inst. Fuel 25, 13-14 (1952). (24) Crossley, H. E., Poll, .4.,Sweett, F., Ibid., 21, 207-9, 213 (1948).
13 1 2
(25) Crumley, P. H . , Fletcher, .i. I$’., Zbid., 29, 322-7 (1956). (26) Crumley, P. H., Howe, H., LVilson, D. S., Gt. Brit. Uept. Sci. 2nd. Research R. S . 39 12A, 1957. (27) Dooley, A , Whittingham, G.? Trans. Faro&? SOL. 42, 354-66 (1946). (28) Engel, B.: E d 0 1 u. Rohle 3, 321--7 (1950). (29) Engineer 204, 459 (1957). (30) Field, J. H., Brunn, I,. hl., othcrs. J . .4ir Poilution Control :Issoc. 7 , No. 2! 109-15 (1957). ( 3 1 i Fletchrr, .A. LV., Chern. 3 I d . (London) 1954, 777-8.
( 3 2 ) Flint, D., J . Inst. Fuel 21, 248-53 (19481.
( 3 j i Flint, D., K e a , K LV., J. .Ippl. Chern. (Lolidon1 1, 388-93 (1951). (34) Flint. D , Lmdsav, .\. IV , Fuel 30, 288 (1951i.
(35) Flint, D., Lindsa), .i. IV., Littlejohn, R. F.. J . Ins:. F7id 26. 122-7 119531. (36) Foster, \V. R., ’ Leipold, hf. H., Shevlin, T. S., Corrosion 12, 539t--48t (19561. (37) Francis, LV. E., Gas Research Board, Communic. No. GRB64, June 1952. (38) Francis, IV., Lepper, G. H., Errginfrring 172, 36-7 (1951).
(39) Gaydon, .I. G., LVhittingham, G.. Proc. Roy. .Cot. (London) A 189, 313---27 (194,).
(40) Geissler, T., Energie 9, S o . 2, 57--9 (19j71. (41) Gerhard, E. -R., Univ. Lficrofilms
(:‘inn Arbor: hfich.), Pub. No. 6946, Dissertation :\bstr. 14, 321 (1954). (42) Gerhard, E. R.. .Johnstone, €1. F., I N D . ENG. C H E h l . 47, 972--6 (1955). (43’8 Gitterman, H., . I l a r i n u 2 , KO. 2, 36----. 40--1 11955): .\farim -Veu:s 41. No. 9,30. 34,~40-1,’43 (19552. (44) Given, hl. D., Pouer Eng. 60, No. 10.
9 -7 ~ ~( 18956’1. -\ -
(45 I Gumz. \I- , Brennstoj- rt’arme-Kruft 9, No. 3. 118 -25 (1957). (461 Hale, F. B. E., .Modern Porcer urrd Eng. 49, N o . 9,73-6 (1955). (47‘1 Harlow, IV. F., Proc. Inst. .\Ipch. Engrr. (London’] 151, 293--309 (1944‘1. 148) Ibid.. 160. 359-79 (19491. (49) Harlow, ’ IY. F.,‘ Trans. ,4m. J’oc. .Merh. Engrs. 80, 225-34 ( 1 958 1 . (50) Henning. F., Rogener, H., L h ~ u r r stqf-H’drme-Krnfl 5 , No. 8, 260 -‘? (1953). (51 1 Hinst. H. F., Heating, Pijing. .du Conditionine 27. No. 1. 166- 9 119551. (52) Hodson-, P:, Trans. .Im. S u r . . l I t ~ / i , Engis. i 7 , 279--86 (19551, (53) Huge. E. C . . Piotter. E. C : Ihid.. 77, 267-78- (19.3.51.(54) Hupfer, H . J., Stanley, R. J., \.an Sickle, X. H.. Ibid., 80, 217---24 (1958 (55) Jenkinson, J . R.: .Uech. En!. 79, 481 ,
\~
Klausncr, I., Barnurn. P. S., f’owe7 Eng. 5 6 , No. 4, 78-80 (1952). (69) Littlejohn, R . F., J . Appl. C%ei/r. (London) 2, 289--94 (1952). (70 1 Littlejohn. R. F.’, ‘IVhittingham. G.. J . Chem. .roc. 1952, 3304-8. (71) Lowenstein-Lom, LV. C ; . (to Stantlard
(68)
Oil Z)evelopmcnt C O . ~ ,Brit. Patrnt 708,095 (April 28, 19541. ( 7 2 ) .Lyons. C. J . , “.I Iicvicw and .\rialysis of Information on External Deposits a n d Corrosion Phenomena in Coal-Fired Boilrrs and Gas ‘Turbinrs,” 71 -91, Battclle hfrinorial Institutr. .olumbus, Ohio (19.56). ( 7 3 ) l l a m a : J. I,,, z n q ~ n i $ r o i 62, 418--19
p.
(1953:. (741 l’askrr, A , , Coiro~iuiif ’ r P z m t . 3 C’onirol 1. 54; -52 ( 1 9 5 4 1 , (75j Pcck: LV.‘ J . , Zaczek, B. J.?Phqiirct.ring 184, 69’ (195-1, ( 7 6 ) Pray. H. .\., Fink, F. \V,, Proplcs. K. S...\in. Gas .4ssoc.. C:omin. on Do-
mestic Gas Krscarch. Rattelle Xicmorial Instirutr. Rept. 1, 194-. 1771 Prav. H. A , . Peoules. K. S.. othrrs. ‘ Ihid., Rirpt. 2. 1949. (78) Kecs, K. I>., J . Ins!. Furl 25, 350 -7 (19531.
(761 R r n d l t ~ .I.. K., LVilstlon, K . I),, Ihid., 29, 3’2-80 (19561. (80) Iioqtmer. H.. H r r n 1 1 s t i ~ ~ - ~ ~ ~ 1 7 m e - F ; r r ~ ~ ~ 9, Nu. 3 , 12668 (lO57!. (81 1 Kothcmich, 13. F., Parmakian, G.. Triins. A m . ,Cor. .tIech. Eners. 7 5 , 723 - 7 : disc. 727-8 119.53). ( 8 2 ) liylands, .I. K., .Tenkinson, J . K.! ,I. h i s t . Fuel 27, 299-318 (19541. (831 Rylands. J . K., Jrnkinson, J. l i . : Proc. Inst. .\lech. B i g r s . ( L o n d u n ) 151, 291--3, 209.309 (19441.
(84) Ihid., 158, 405--25 (19481. (85) ‘laylor, .\. .\,, .I. Ztist. k’uel 16, 2.5 4 (1942). (861 Taylor, €-I. I)., Tr0n.r. Foradny .Tor. 47, 1114-20 (1951). (87 1 Taylor! R. P., Lewis, A , , IV Congr. intt>m. chariffagr ind., Paris, 1952, Pre-
I
~~
8.
/.I
nz-,
( l Y 2 l J .
(56) .Johnstone, H. F.: Univ. of Illinois Bull. 27, No. 13 ( 1 9 2 9 , Eng. Lxp. Sta. Circ. No. 20, 22 pp. (571 Ibid., 28, No. 41 (1931 1, F.nS. ESP. Sta. Bull. No. 228, 120 pp. ( 5 8 ) Johnstone. H. F.: Coughanowr. D. K., Division of Industrial and Engineering Chemistry, 1 3 2 n d hfeeting: ACS, New York, September 1957. (59) Juhasz, S., Cornbus:ion 20, No. 12, 55-8 (19491. (60) Kear, R. LV., B u l l . Brit. Coal C‘tilisntion Research Assoc. 19, 297-318 (1955). (61) Kear: R. I V . , Fuel 33, 119--20 (1954~1. (62) Kear, R.W., J . 4@1. Chem. (London) 1, 393-9 (1951). (63) Zbid., 4, 674-9 (19543. (64) Ibid., 5 , 237-42 (1955). (65) Ibid., 5 , 260-6 (1955). Whittingham, G., Fur/ (66) Kear, R.W., 32, 265-78 (1953). (67) Kerr, R.,Withers, S. hi., J . Inst. Fuel 22, 204-8 (1949).
INDUSTRIAL AND ENGINEERING CHEMISTRY
67, 411-4 (3948,. [,96) IVliittin~harn, G., .\.dure ~
157, 550 (1946’1. (97; Ihid.. 169, 15.7 -6 (19521, ( 9 8 1 LVhittingharn. G., Proc. Inierii. C o n q . Pure and :lfij/.Chern. i l i h Corigr. 4, 591 -9 ( 1 0 4 7 ) ; T r k . 7‘idsX.r. 80, 699-704 (1950). (99) IVhittingham, G., Proc. ‘Third S y m -
posium on Combustion and Flame and Explosion Phcnoinena, pp. 453-9, hfadison, Wis., 1948. (100) IVhittingham, G., % a m . F~mdu.ia_y Sod. 44, 141-50 (1948). f l O l 1 LVidell. T.. Cornbustion 24. No. 12. 53-5 (1953).
02’1 LYilsdon, K. D., Kendlr, I>. K .
(to British Petroleum Co. 1, Brlqian Patent 549,406; Rec. bre:’ets inz’eiiiion
1956, 1316--17. 03) Zaczek, B. J., Grindley, K., Eii,qineering 184, 825 (1957). RECFIVED for review December 5, 1958 ACCEPTED
.April 15, 1959
