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Energy & Fuels 2007, 21, 242-249
CFD Evaluation of Waterwall Wastage in Coal-Fired Utility Boilers James R. Valentine,* Hong-Shig Shim, and Kevin A. Davis Reaction Engineering International, 77 West 200 Street, Suite 210, Salt Lake City, Utah 84101
Sang-Il Seo and Tae-Hyung Kim Korea Electric Power Research Institute, Daejeon, Korea ReceiVed May 8, 2006. ReVised Manuscript ReceiVed September 12, 2006
With the advent of substoichiometric low NOx combustion in coal-fired utility boilers during recent years, problems with waterwall corrosion have increased. A predictive tool capable of assessing corrosion potential and aiding in the design of problem solutions could help alleviate the utility downtime and cost associated with waterwall wastage. Waterwall wastage has been associated with various mechanisms, including gaseous phase reducing sulfur species, wall deposition of unoxidized sulfur fuel, and fuel chlorine. Integration of predictive correlations for corrosion into a computational fluid dynamics (CFD) code can provide a framework for evaluation of corrosion potential. In this paper, CFD studies and predictions of corrosion in five utility boilers are examined and compared with observed wastage. The CFD code makes use of approximations of empirically developed corrosion correlations for gaseous phase reducing sulfur species, wall deposition of unoxidized sulfur fuel, and fuel chlorine. Model corrosion predictions are compared with observed or measured wastage in several coal-fired utility boilers, including tangentially fired, wall-fired, and cyclone-fired units.
Introduction With the imposition of increasingly stringent NOx emissions limits during recent years, combustion modifications such as the use of low-NOx burners (LNBs) and over-fire air (OFA) have become commonly used strategies for achieving NOx emission reductions in large utility coal furnaces. Although these methods are effective and inexpensive to implement and operate, there are some adverse impacts, notably increases in furnace fireside waterwall wastage in fuel rich or alternating fuel rich/ fuel lean regions. Some furnaces have experienced local tube metal loss rates of the order of 2.5 mm/yr (100 mil/yr) and EPRI recently estimated that fireside corrosion costs the U.S. electric power industry up to $590 million per year and is responsible for approximately half of unscheduled outages in steam generation units.1 However, not all units experience waterwall corrosion under low-NOx firing conditions; the susceptibility of a particular unit is dependent on fuel composition, furnace design, and furnace operation. Limited fuel availability is often a complicating factor; chlorine-containing Illinois Basin coals are becoming more commonly burned, and low-sulfur Eastern Bituminous coals are often shipped overseas, leaving less desirable fuels for domestic U.S. consumption. The goal of this study is development of a CFD-based predictive tool for assessment of boiler waterwall corrosion potential. This type of tool has value in the prevention of waterwall wastage through evaluation of the impact of planned operational or physical furnace modifications or as an aid in troubleshooting current wastage problems. To accomplish this goal, correlations describing corrosion must be incorporated into a CFD code. The complexity and often the uncertainty of actual furnace wall conditions make the development of correlations * Corresponding author e-mail:
[email protected]. (1) Syrett, B. C.; Gorman, J. A. Mater. Perform. 2003, 42, 32-38.
from fundamental principles impractical. Duplication of furnace heat fluxes, temperature gradients, and flue gas and ash deposit conditions are difficult in the laboratory; pilot-scale results may be most applicable to actual furnace conditions. Here we consider incorporating approximations of previously developed correlations into a CFD code and compare predictions to observed or measured waterwall corrosion in utility furnaces. An effort is currently underway to refine the correlations through evaluation of electrochemical sensing in a pilot-scale furnace.2 Waterwall corrosion has been linked to fuel composition, primarily fuel sulfur and chlorine content, and to local combustion conditions such as near-wall flue gas composition and stoichiometry, tube metal temperature, wall deposit characteristics, wall heat flux, and wall flame impingement. Although details of the actual mechanisms involved are not completely understood and are currently actively researched, recent work has identified three mechanisms for waterwall wastage in coalfired utility boilers:3,4 (1) Gas-phase attack by reduced sulfur species such as H2S formed under the fuel-rich conditions of low-NOx firing systems; (2) Deposition of unoxidized fuel and impurities on furnace waterwalls, leading to near-tube sulfidizing conditions; (3) Chlorine-based attack under local high heat flux reducing conditions. Ongoing work by the Korea Electric Power Research Institute includes further development and refinement of corrosion correlations through pilot-scale studies.4 Of the three corrosion (2) Davis, K. A.; Linjewile, T. M.; Valentine, J. R.; Swensen, D.; Shino, D.; Letcavits, J. J.; Sheidler, R.; Cox, W. M; Carr, R. N.; and Harding, N. S. Anti-Corrosi. Methods Mater. 2004, 51 (5), 321-330. (3) EPRI, Waterwall Wastage Mechanisms in Coal-Fired Boilers: The Effect of Coal Chemistry on Waterwall Wastage; 2001; TR-1004021. (4) Reaction Engineering International, DeVelopment of AdVanced Fireside Waterwall Corrosion Model for PulVerized Coal Fired Facilities; KEPRI Annual Report 2, 2005.
10.1021/ef0602067 CCC: $37.00 © 2007 American Chemical Society Published on Web 11/18/2006
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mechanisms listed above, gas-phase H2S attack is the best understood and can be estimated with an empirical correlation for carbon and low-alloy steels with 0 e Cr wt % e 10 developed by Kung:5
(
CR ) 3.2 × 105 exp -
15,818 × [H2S]0.574 × 1.987T 1 ( 2.2 (Cr % + 10.5)1.234
)
where CR is the corrosion rate in mil/yr (1 mil/yr ) 0.0254 mm/yr), T is the metal temperature in Kelvin, H2S is the flue gas concentration of H2S in mg/kg, and Cr % is the percent of metal Cr content by weight. However, corrosion rates described by these correlations are much lower than the overall maximum rates observed in actual boilers, indicating that other mechanisms are involved.6 Corrosion resulting from waterwall deposition of unoxidized material has been investigated by Bakker and co-workers.6-8 Studies have focused primarily on deposition of unoxidized FeS, which results from the decomposition of pyrite (FeS2) existing as an impurity in the coal. Studies have indicated that (1) Metal coated with an FeS layer and placed in a flue-gaslike environment may experience corrosion rates much higher than those due to gas-phase H2S, and the corrosion rate appears to be independent of FeS content of the coating. The presence of carbon in the coating may increase corrosion rates. (2) Corrosion rates resulting from an FeS coating are highest under local gas-phase oxidizing conditions. (3) Alternating oxidizing/reducing conditions occurring through normal load and operational cycling in the furnace may result in high wastage through removal of protective tube metal oxide scales that are built up under oxidizing conditions. Chlorine-based corrosion has been a problem in Great Britain for a number of years and has more recently been observed in some U.S. boilers. It has been associated with reducing conditions and high wall heat fluxes and can result in very high metal wastage rates. Davis et al.9 have developed a correlation developed to describe corrosion rate under reducing conditions (O2 < 0.5% and CO > 2%) in the presence of chlorine:
( )
CR ) (C × % Cl) × (HF)m × exp -
Qcl -d RT
where CR is the corrosion rate in mm/yr; C, m, Qcl, and d are constants; % Cl is the wt % of coal chlorine content; T is the metal surface temperature; and HF is the wall heat flux. Note that this correlation inherently assumes uniform dispersion of fuel chlorine throughout the furnace. A predictive tool for assessing waterwall corrosion has been developed through incorporation of correlations describing waterwall corrosion into Reaction Engineering International’s in-house reacting, two-phase flow computational fluid dynamics (CFD) code GLACIER.10-13 GLACIER has been used extensively in the modeling of physical and chemical processes (5) Kung, S. C. Mater. Perform. 1997, 36 (12), 36-40. (6) Bakker, W. T. Mater. High Temp. 2003, 20 (2), 161-168. (7) Bakker, W. T. Wastage in Low NOx Boilers, Root Causes and Remedies; EPRI Report TR11115; 1998. (8) Bakker, W. T.; Kung, S. C.; Heap, M. P.; Valentine, J. R. Proceedings of the EPRI-DOE-EPA Combined Utility Air Pollution Control Symposium: The MEGA Symposium, Volume 2: NOx and Multi-Pollutant Controls; 1999; pp 13-17-13-30. (9) Davis, C. J.; James, P. J.; Pinder, L. W.; Mehta, A. K. Mater. Sci. Forum 2001, 369-372, 857-864. (10) Smoot, L. D.; Smith, P. J. Coal Combustion and Gasification; Plenum Press: New York, 1985.
occurring in industrial furnaces, particularly coal-fired utility boilers. The governing gas-phase equations for fluid motion and reaction are solved in an Eulerian framework with turbulence accounted for through a k- model. Reaction rates are assumed to be mixing limited. Transport equations are solved for mean values of mixture fraction values and variances about the mean. Convolution of probability density functions (pdf) is used to obtain local chemical composition, temperature, and other properties.10 Particle mechanics are included in GLACIER through tracking of the mean path and dispersion of ensembles or “clouds” of particles.12 Dispersion is determined with input from the local gas-phase turbulent flow field. Particle reactions include liquid evaporation, devolatization, and heterogeneous oxidation. Particle mass, momentum, and energy source coupling with the gas phase is accounted for through a particle-source-in-cell technique.14 Particle wall deposition is included through the evaluation of particle wall interactions. Transport of thermal radiation and surface heat fluxes are calculated using a discrete ordinates method, including the effects of variable surface properties and participating media (gas, soot, and particles).13 The predicted local gas-phase combustion field and waterwall conditions are used in conjunction with empirical corrosion correlations to evaluate waterwall corrosion. The correlation for gas-phase H2S attack-based corrosion above can be used directly in GLACIER, but correlations for corrosion due to deposition of unoxidized material and fuel chlorine are approximated. For the deposition of unoxidized material, an expression of the form
CR ) A × f(SR) × e-(Q/RT) where SR is the local stoichiometric ratio,
f(SR) ) B × (1 - SR)n + D for SR < 1 and
f(SR) ) C × (SR - 1)m + D for SR g 1 Local CO and O2 concentrations approximated from the stoichiometric ratio and constants A, B, C, D, n, m, and Q are evaluated from published empirical data plots.6,8 This expression has been used to evaluate corrosion potential in regions where GLACIER predicts deposition of unoxidized material. In a similar manner, constants in the expression for chlorine corrosion are also evaluated from plotted empirical data,15 and the resulting approximate expression is used to evaluate chlorinebased corrosion in reducing regions using input from the GLACIER-predicted combustion field. The constants in the original correlations are not available, necessitating the used of approximations from published plots. Case Studies Deposit-Based FeS Corrosion in Two Pulverized Coal Utility Boilers. The first unit evaluated for corrosion was a (11) Smith, P. J.; Fletcher, T. H. Combust. Sci. Technol. 1988, 58, 6876. (12) Smith, P. J. 3-D Turbulent Particle Dispersion Submodel DeVelopment; DOE Quarterly Progress Report 4; 1992. (13) Adams, B. R.; Smith, P. J. Combust. Sci. Technol. 1993, 88 (5-6), 293-308. (14) Crowe, C. T.; Sharma, M. D.; Stock, D. E. J. Fluids Eng. 1977, 99, 325-332. (15) Davis, C. J.; James, P. J.; Pinder, L. W.; Mehta, A. K. Furnace Wall Fireside Corrosion in PF-Fired Boilers: The Riddle Resolved. Presented at United Engineering Foundation Conference on Effects of Coal Quality on Power Plant Management: Ash Problems, Management and Solutions, 2000, Park City, UT.
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Figure 2. Rate of rear wall deposition of unreacted fuel (left) and the fraction of unreacted fuel in the material deposited (right). Figure 1. Map of measured corrosion for front and rear walls of the tangentially fired furnace with near-wall flow direction and maximum measured tube wastage labeled.
Combustion Engineering 850 MW tangentially fired, supercritical divided twin boiler consisting of two identical furnaces sharing a common center wall. The furnace has eight levels of burners located on the front and rear walls near the corners and burns a 1.8% sulfur eastern bituminous coal. For modeling purposes, half of the twin furnace was evaluated. After being retrofitted with a Low NOx Concentric Firing System (LNCFS) Level III, the furnace began to experience severe waterwall corrosion in the front and rear wall SOFA region and in the burner region of the “hot corners”. A map of measured front and rear wall corrosion is shown in Figure 1. Wastage rates are calculated from UT tube thickness measurements taken approximately 2 years apart. Colored regions in the hot corners along the burner stacks and at the SOFA elevation indicate high corrosion. Side wall corrosion was far less significant than that of the front and rear walls. The first step in using GLACIER to assess corrosion potential is evaluation of deposition of unoxidized fuel. The predicted rear furnace wall deposition rate of unoxidized material and the oxidation state of the deposited material as deposited are shown in Figure 2. In analyzing predicted characteristics of the high corrosion region, the focus will be on the rear wall; predicted front and rear wall characteristics are similar. The location of high rates of unreacted fuel deposition correlates well with high measured SOFA region corrosion. Prediction of corrosion rates is based on the fraction of unoxidized material in the total material deposited and, although Figure 2 shows that predicted values are high over large regions of the furnace rear wall, over most of these regions the deposition rate is very low. Thus, in predicting corrosion, it appears necessary to use both the deposition rate of unoxidized material and the fraction of unoxidized material in the total material deposited. As noted earlier, empirical evidence indicates the highest corrosion rates occur where deposits of unoxidized material are present in locally oxidizing or nearly oxidizing regions. Figure 3 shows predicted CO concentration at the furnace rear wall
Figure 3. Predicted CO concentration at the furnace rear wall and 6 in. from the rear wall.
and 6 in. from the rear wall. Although high CO concentrations are not predicted at the rear wall over much of the high corrosion region, high concentrations are predicted a few inches away. This indicates that the high corrosion region may be subject to alternating reducing/oxidizing conditions as furnace conditions change. Although the furnace is normally subject to changes in operation during a typical day and near-wall conditions may change with changes in operation, one set of fixed conditions is modeled. It is suspected that alternating oxidizing/reducing conditions near furnace waterwalls may exacerbate corrosion through destruction of protective scales built up under oxidizing conditions. Predicted corrosion rates for the furnace front and rear walls are shown in Figure 4. Predicted rates are based on deposition of unburned fuel rather than the actual deposition of unoxidized
CFD EValuation of Waterfall Wastage
Figure 4. Predicted FeS or deposit-based corrosion rate.
FeS. Waterwall corrosion is predicted in the SOFA region and in the so-called hot corners where wastage has been observed in the furnace. Hot corners are on the upstream edge of the front and rear walls; the rear wall hot corner is adjacent to the right wall. H2S- and chlorine-based corrosion were also examined, but in this case those predicted rates were much lower than rates due to deposition of unoxidized fuel. For this furnace, a CFD-based waterwall corrosion predictive tool can accurately predict waterwall wastage locations and thus help to alleviate the problem. A second furnace examined for FeS-based waterwall corrosion was a 1300 MW supercritical opposed wall-fired unit. The furnace is fitted with 112 single register low NOx burners in a cell arrangement and burns a bituminous coal of approximately 3.5% sulfur content on an as received basis. In opposed-wallfired boilers, flames from opposite wall burners typically impinge on each other at the furnace center and spread toward the side walls. The central part of the side walls in the burner zone is thus often subject to high heat flux, reducing conditions, and high rates of unoxidized fuel deposition. These conditions may in turn lead to side wall corrosion with more severe problems in supercritical units such as this one due to higher tube temperatures. Side wall boundary air is sometimes used to alleviate the problem. In this particular furnace, secondary burner air is biased away from the central burners toward the outer near side wall burners, so the outer burners have 1.67 times the secondary air of the inner burners. Apparently, this is an attempt to maintain more oxidizing conditions near the side walls and to alleviate side wall corrosion. Measured side wall wastage for this furnace is shown in Figure 5. Wastage follows the typical pattern for opposed wallfired units as described above. Right side wall corrosion extends higher in the furnace than that of the left side wall, probably due to either intentional or unintentional asymmetrical operation of the furnace that is not accounted for in the model. The predicted left side wall deposition rate of unoxidized material and the oxidation state of the deposited material as deposited are shown in Figure 6; patterns are qualitatively similar for the right side wall. The location of high rates of
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Figure 5. Side wall waterwall wastage for the opposed wall-fired boiler.
Figure 6. Rate of left side wall deposition of unreacted fuel (left) and the fraction of unreacted fuel in the material deposited (right).
unreacted fuel deposition correlates well with high measured SOFA region corrosion. As with the previously examined furnace, peak values of both are predicted in the vicinity of the high measured wastage area. Again, regions are present where the fraction of unreacted fuel in the total material deposited occur, but the overall deposition rate is low. Predicted near-wall CO concentration and FeS-based corrosion rate are shown in Figure 7. Peak CO is predicted in the high corrosion region, but empirical evidence indicates that unreacted fuel deposited in such strongly reducing regions
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Figure 7. Left side wall near-wall predicted CO concentration and FeS-based corrosion rate.
should be inert and not corrosive. As a result, the FeS corrosion correlation predicts the highest corrosion outside the high CO region. The discrepancy between actual and predicted maximum corrosion locations could be due to variation in near-wall conditions during normal daily load cycling of the boiler (modeling was done at full load) or the impact of other mechanisms. One such mechanism is H2S-based corrosion, predicted values for which are shown in Figure 8. H2S corrosion occurs in reducing regions such as is predicted for the location of actual side wall corrosion, but maximum rates are much lower than those of deposit-based corrosion and are too low to account for the extremely high corrosion rates observed in some furnaces. Here the maximum predicted H2S corrosion rate is 25% of that predicted for FeS or deposit-based corrosion. Predicted wall heat flux is also shown in Figure 8; peak values are present in and near the region of observed corrosion, as is often the case. Although the heat flux impacts chlorine-based corrosion, any impact on FeS- or deposit-based corrosion is not explicitly accounted for. Heat flux might affect corrosion rates through increases in deposit and tube wall temperature gradients that increase thermal stresses or diffusion of corrosive species through the surface layers. Since the chlorine content of fuel burned in this furnace was less than 0.05%, chlorine-based corrosion should not have an impact here. Chlorine-Based Corrosion in Three Coal-Fired Utility Furnaces. Chlorine-based corrosion is examined in three coalfired utility furnaces: a 500 MW opposed wall cyclone-fired boiler, a 377 MW tangentially fired furnace, and a 350 MW front wall-fired furnace. The cyclone-fired unit is equipped with ten opposed cyclone barrels, five on each of the front and rear walls, in the lower furnace refractory lined region. Above the upper extent of the refractory, 10 OFA interlaced OFA ports are arranged five on each of the front and rear walls. Gas tempering ports are present higher in the furnace. Approximately 1 year after being fitted with OFA ports for low NOx operation and beginning staged
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Figure 8. Left side wall predicted H2S corrosion rate and net wall heat flux.
Figure 9. Predicted net wall heat flux and chlorine-based corrosion rate.
operation, an examination of furnace walls during a shutdown showed no unusual waterwall wastage. However, 1.5 year after the initial examination, a second examination revealed a severe waterwall wastage problem immediately above the upper extent of the refractory lined walls. The unit typically burns a PRB/bituminous coal blend with the specific coal type and blend composition varying with spot market availability and power demand. A high level of bituminous coal is generally used under high demand conditions.
CFD EValuation of Waterfall Wastage
For up to 2 years prior to the discovery of high wastage, a high chlorine content (0.40% as received) Illinois Basin bituminous coal had been burned. CFD simulations of the furnace were performed with a 10/ 90 Illinois/PRB coal blend and with a 40/60 Illinois/PRB blend. Negligible waterwall corrosion was predicted for the 10/90 blend, but high chlorine-based wastage rates were predicted for the higher bituminous content 40/60 blend. This is precisely the same as plant observations; when the high chlorine Illinois coal made up a lower level of the blend burned in the furnace, no waterwall wastage was observed. Overall fuel chlorine content was 0.055% for the 10/90 blend and 0.17% for the 40/ 60 blend. Predicted net wall heat flux and corrosion rate for the latter are shown in Figure 9. At the upper extent of the refractory walls, wall heat flux increases sharply. This region is just below the OFA ports so is overall substoichiometric. Coupled with the high heat flux and substoichiometric conditions, the higher fuel chlorine content in the 40/60 blend leads to corrosion. Maximum predicted heat fluxes above the upper limit of the furnace wall refractory were significantly higher than typical furnace maxima. The model does a good job of predicting the locations, although the rates may be somewhat low due to uncertainties in predicted tube metal temperatures. Examination of H2S-based corrosion in this furnace resulted in maximum predicted rates of 2-3% of those predicted for chlorine-based corrosion. Deposit- or FeS-based corrosion was not considered for this furnace, but it is expected that it is not as significant as that due to chlorine. While the fuel chlorine content is high, sulfur content is low (
