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Prediction and Real-time Monitoring Techniques for Corrosion Characterisation in Furnaces Temi M. Linjewile, James Valentine and Kevin A. Davis Reaction Engineering International N.S. Harding N.S. Harding & Associates William M. Cox Corrosion Management

ABSTRACT Combustion modifications to minimise NOx emissions have led to the existence of reducing conditions in furnaces. As regulations demand lower NOx levels, it is possible (to a degree) to continue to address these requirements with increased levels of combustion air staging. However, in most practical situations, a number of adverse impacts prevent the application of deep combustion air staging. One of the more important limitations is the increased corrosion that can occur on wall tubes exposed to fuel rich combustion environments. Current boiler corrosion monitoring techniques rely on ultrasonic tube wall thickness measurements typically conducted over 12 to 24 month intervals during scheduled outages. Corrosion coupons are also sometimes used; typically require considerable exposure time to provide meaningful data. The major drawback of these methods is that corrosion information is obtained after the damage has been done. Management of boiler waterwall loss and system optimisation therefore requires a real-time indication of corrosion rate in susceptible regions of the furnace. This paper describes the results of a program of laboratory trials and field investigations and considers the use of an on-line technology in combination with innovative applications of CFD modelling and precision metrology to better manage waterwall loss in fossil fuelled boilers while minimising NOx emissions. INTRODUCTION Combustion modifications, including low-NOx burners (LNBs) and over-fire air (OFA) have proven to be one of the most cost-effective solutions for minimisation of NOx emissions. This approach however often leads to the existence of reducing conditions and flame impingement at waterwalls. As regulations demand lower NOx levels, it is often possible to address these requirements with increased combustion air staging. However, in most practical situations, a number of adverse impacts prevent the application of deep staging. One of the more important limitations is the increased extent of waterwall corrosion. In utility boilers, for example, staging has increased the frequency and severity of waterwall wastage, with rates exceeding 2.5 mm/yr in some units. The industry-wide significance of this problem is pointed out by EPRI estimates indicating that fireside corrosion costs the U.S. electric power industry up to $590 million per year [1]. The susceptibility of particular units has been attributed to the effects of several features including fuel selection, tube temperature, and firing system design. Formulating solutions to this problem can be complicated by the range of potential corrosion mechanisms, which can involve gas-phase sulphur and/or chlorine in addition to the direct deposition of unreacted fuel. The physics and chemistry controlling corrosion processes can be highly non-linear. 1

Therefore, brief periods of exposure to unusual conditions can dominate the overall material loss between inspections. Due to the complex relationships between corrosion and its controlling factors, in addition to the difficulty in assigning periods of high corrosion to specific operational factors, the ability to understand, monitor, and manage boiler waterwall loss could be dramatically improved through the application of predictive modelling techniques along with a verifiable, real-time corrosion monitoring system. APPROACH The availability of practical tools for analysing corrosion in a coal-fired boiler is limited. Waterwall corrosion is thought to be dependent upon local waterwall conditions and their relationship to fuel properties, operating conditions, and boiler/firing system configuration. Therefore a predictive model requires 3D, two-phase computational fluid dynamics (CFD) software that incorporates relationships between corrosion rates and these local conditions. Although there are no broadly accepted correlations a few useful relationships have been developed. On-line high-temperature corrosion monitoring is also a developing technology. An evaluation of existing technologies revealed that no real-time monitoring options had achieved industry-wide acceptance. It was important, therefore, for any monitoring technology used to be verified against physical measurements during a period of stable operation. As boilers are rarely operated in a stable manner for an extended period (e.g. due to load variation, fuel property variation, and operator tendencies), it was considered useful that such checks might be undertaken during a period as short as a single operator’s shift. With these concepts in mind, this paper focuses on the development of CFD tools and field instrumentation to use in a complementary approach to corrosion management. The following sections detail progress in these three areas, i.e. CFD modelling, electrochemical monitoring and surface profilometry, as applied to several coal-fired utility boilers. CFD MODELING The predictive modelling tool discussed herein was based on the CFD code GLACIER [2], which had been tailored for application to reacting, two-phase flow systems. The approach to modelling the fate of fuel/ash particles provided a convenient basis for implementing descriptions of phenomena such as deposition and corrosion. The mean path and dispersion of an ensemble of particles, referred to as a “particle cloud,” were tracked in a Lagrangian reference frame. Dispersion of the cloud was determined with input from the turbulent gas flow field. Particle mass, momentum, and energy sources were coupled to the gas flow field through a particle-source-in-cell technique [3]. Particle reaction processes included coal devolatilisation, char oxidation, and liquid evaporation. Waterwall deposition was accounted for by evaluating particle/wall interactions. Corrosion rates in a boiler can be predicted using GLACIER in conjunction with empirical correlations relating corrosion rates with predicted properties of the boiler. Although the mechanisms responsible for the corrosion of furnace waterwall tubes are not generally agreed upon, recent work indicated there may be three mechanisms for waterwall wastage in U.S. coal-fired boilers [4-8]: •

Gas-phase attack by reduced sulphur species such as H2S

•

Deposition of unreacted fuel and resulting sulphur-based attack

•

Chlorine-based attack

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Currently, the details of these mechanisms are topics of active discussion. However, laboratory, pilot-scale and full-scale work was performed from which specific correlations were developed for each of these mechanisms. In addition Reaction Engineering International and EPRI have applied these correlations within CFD simulations for a number of utility boilers and, with little modification to the correlations, have been able to effectively demonstrate their usefulness based on field observations. Hydrogen Sulphide

Corrosion Rate (mm/yr)

The presence of reduced sulphur species near furnace waterwalls is known to result in tube metal corrosion. Correlations based on laboratory experiments were developed relating corrosion rates to tube temperature, steel composition, and H2S concentration [4, 5]. By implementing one such correlation [4] into a post-processor for use with GLACIER, local corrosion rates may be estimated for coal-fired boilers. The correlation requires local information regarding tube temperature and H2S concentration as well as the weight % chromium of the tube material. Recent studies have shown that this gas-phase mechanism tends to result in a second order effect for boilers that are experiencing high corrosion rates (>0.5 mm/yr). As illustrated in Figure 1, even at temperatures and H2S concentrations at the high end of the range encountered in coal-fired boilers, the corrosion rates from gas-phase sulphur attack are limited.

Tube Temp = 343 C

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H2S Concentration (ppm) Figure 1 - Corrosion rate as a function of tube temperature and H2S concentration, as predicted by an existing correlation [4] Deposition of Unreacted Fuel The magnitude of corrosion rates in the lower furnace of coal-fired boilers that have been retrofitted with LNBs and OFA has exceeded that expected from a strictly gas-phase attack involving sulphur. The presence of sulphur in wall deposits has been implicated as a possible explanation for this behaviour [9]. Providing a detailed description of the sulphur-containing material depositing on waterwalls requires more than a simple description of fuel pyrolysis and oxidation. For example, fuel-sulphur can exist in multiple forms including pyritic, organic and sulphatic forms. In addition, during pulverisation, much of the pyritic fraction can be separated from the organic matrix (herein referred to as excluded). The thermal decomposition and oxidation of the sulphur can occur at rates that are dissimilar to the bulk

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coal. In addition, the aerodynamics of the typically smaller denser excluded pyrite can result in particle trajectories that vary from the bulk coal. In order to more accurately model the transport and deposition of sulphur within a coal-fired boiler, the following steps can be taken: •

Computer-Controlled Scanning Electron Microscopy (CCSEM) characterisation of the fuel

•

Separate treatment of the thermal decomposition and oxidation of excluded pyrite and included sulphur forms (pyritic and organic)

Fraction of Initial Remaining

The thermal decomposition and oxidation of excluded pyrite has been studied in detail and the model of Srinivasachar and Boni [10] was the basis for the approach implemented in GLACIER [11]. CCSEM analyses can be 1.2 used to define the size of the pyrite Carbon particles and the amount in 1 Total Sulfur excluded/included form. Although the Pyrite 0.8 evolution of pyritic and organic sulphur Organic Sulfur from within the coal matrix is not well 0.6 understood, a complementary lab-scale study [12] has provided insight for the 0.4 detailed modelling approach. This study 0.2 of four coals suggested that organic sulphur was released in proportions 0 0 10 20 30 40 50 60 70 roughly equivalent to that of the bulk coal % Burnout as illustrated in Figure 2. However, sulphur from pyrite, while also released in Figure 2. Sulfur release during coal char a nearly proportional manner during oxidation [12] oxidation, was preferentially released during pyrolysis. The extent of pyrite decomposition seemed to vary from coal to coal indicating that an accurate accounting may require coal-specific testing. Based on these models for pyrite and organic sulphur evolution, as well as EPRI laboratory studies to quantify the impact of sulphur deposition on waterwall wastage, corrosion rate correlations have been developed and evaluated using several test cases. In general terms this CFD-based effort illustrates that this approach can be used with very good agreement between predicted and observed corrosion rates. Figure 3 is an example of this comparison for a large pulverised coal-fired boiler.

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Rear Wall

(max = 2 mm/yr)

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Side Wall

(max = 0.65 mm/yr)

(max = 2.35 mm/yr)

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(max = 0.73 mm/yr)

> 1.75 (scale for simulations)

mm/yr 0

Figure 3 - Field measurements and CFD-based predictions of waterwall wastage The figure shows a comparison between measured ultrasonic tube wall thickness contours for the waterwall and CFD predictions. This and the other test cases suggest that this tool can be applied to a range of firing configurations, firing rates and fuel types. Chlorides The critical role of chlorine in specific boiler environments has been accepted for many years. The experience in the UK power industry has been documented in several studies at various scales [6] and the impact of chlorine in corrosion processes within waste boilers is well recognised. Further, the potential for chlorine-associated corrosion in biomass-fired boilers has recently been investigated by Nielsen et al. [7]. However, the mechanism by which this corrosion process occurs and the conditions under which chlorine plays an important role within coal-fired boilers are not established. Recently, efforts have been made to reconcile conflicting conclusions in this area and to focus on quantitative correlations under relevant conditions [8]. These correlations, which involve coal chlorine content, heat flux, and tube temperature, were added to the corrosion predictor model and evaluated through application to a few boilers that were (1) experiencing severe corrosion problems and (2) burning high chlorine coal. In each case, the location and approximate rate of corrosion indicated agreed reasonably well with field observations.

ELECTROCHEMICAL MONITORING The CFD tools mentioned previously provide valuable insight in diagnosing existing corrosion problems and in identifying the potential impact of fuel, firing system, or boiler modifications. However, effective management of corrosion within a boiler often requires real-time measurements. Serious tube damage can occur in relatively brief time frames due to a number of potential irregularities that can be difficult to identify from control 5

instrumentation, such as excursions in fuel properties, equipment failure, malfunction of sensors providing feedback for control loops, or operator error. A real-time sensor that can detect the overall contribution of such effects on the relative corrosivity of the combustion gas to the tube material allows the damaging conditions to be recognised and addressed immediately. Real time sensing complements CFD modelling in other ways; high temperature corrosion mechanisms in coal-fired boilers are not well understood and the robustness of the available empirical correlations is not well known. At best such correlations should be considered only to be semi-quantitative in nature. In addition, it is often difficult to develop a complete and accurate description of the various inputs for a model of a coal-fired boiler (e.g., fuel and air distribution, wall deposition conditions). A real time electrochemical sensor therefore can provide important verification of the validity of the input description, and a ‘safety net’ if unanticipated or undisclosed circumstances – such as an unexpected change in fuel supply source – place the boiler at risk. Monitoring high temperature corrosion in a reliable, effective, and timely manner is a challenging task. Techniques that have been effective for identifying corrosion after-the-fact include visual inspection and ultrasonic tube-thickness measurement. Under conventional combustion conditions, corrosion rates in a boiler typically should be less than 0.25 mm/yr and off-line inspection techniques allow plant personnel to track tube damage rates during scheduled outages. However, as a result of the widespread introduction of reducing combustion conditions for NOx control, and the increased time between scheduled outages, costly tube failures due to waterwall corrosion have become more common. Retrospective damage quantification techniques provide little insight into the causes of corrosion and make it difficult to do much more than repair the damage, often during forced outages. Corrosion coupons could be used to evaluate corrosion rates between outages, and additional analyses may provide some understanding of a particular mechanism involved. However, accurate control of the operating temperature of such coupons is difficult and the results of coupon tests are notoriously unreliable. Corrosion damage may occur over a period of several months and the resulting information is therefore of limited value in improving control or evaluating the impact of specific operating conditions, or even characterising fuel properties, though the use of specially tailored coupons, in combination with optical or scanning microscopy, has proven useful in pilot plant studies [8]. On Line Corrosion Monitoring Equipment In order to obtain a real-time indication of corrosion risk, a measurement system based on electrochemical sensing was utilised, The system comprised a temperature-controlled electrochemical sensor, signal conditioning and data acquisition modules, a temperature controller, cooling air supply and a computer for data processing. The instrumentation data acquisition modules and temperature controller were enclosed in a rugged dust-free metal enclosure. Air cooling enabled the operating temperature of the sensor elements to be controlled at the same temperature as the adjacent boiler tubes. The principle of operation of the instrument is that spontaneous fluctuations in the electrical potential and current signals measured occur during corrosion. The fluctuations are converted to a digital signals and supplied to a computerised data acquisition unit. An estimate of the rate of corrosion, ICorr,, is obtained by replacing the polarisation resistance (Rp) in the standard Stern-Geary equation and converting the corrosion current value so obtained to an equivalent metal loss rate by application of Faraday’s Law [13]:

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I Corr =

B Rn

where B is the Stern-Geary coefficient. Corrosion rate is computed as a product of the corrosion current density and the material constant. The material constant is a term encompassing the atomic mass of the sensor plate material, Faraday’s constant, number of electrons produced in the anodic reaction (2 electrons in this case), and the density of the plates. Laboratory and Pilot-scale Corrosion Tests

During the past two decades, efforts have been made to take real time corrosion monitoring technologies, which have been used successfully in low temperature applications, and exploit their usefulness in higher temperature combustion environments. Although these adaptations have been successful in certain industries [14], the power industry has been slow to take up the technology. Following a preliminary evaluation of available technologies, electrochemical sensing technology was identified as a promising option for further development and evaluation [15]. Tests for studying the ability of the corrosion sensors to respond to changing combustion stoichiometry were conducted in a pilot-scale combustion test facility at the University of Utah. Figure 4 shows the results of a particular test where stoichiometry was varied from 0.85 to 0.95. It is clear from the figure that the corrosion rate is influenced by combustion stoichiometry. 0.25

Corrosion Rate (mm/yr)

S.R. = 0.90

S.R. = 0.95

S.R. = 0.90

S.R. = 0.85

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Figure 4 - Corrosion rate responding to changes in combustion stoichiometry. It is manifested that the more reducing the conditions, the higher is the corrosion rate. Harb and Smith [16] report that reducing conditions are a consequence of poor combustion conditions resulting in low oxygen concentration, increased CO concentrations and the presence of H2S. Full-scale Plant Corrosion Tests 7

A formal field test was arranged in order to further evaluate the qualitative and quantitative reliability of the technology in an industrially relevant environment. In addition, following the set-up period, the reliability of remote control data collection was considered. A schematic of the 600 MWe, supercritical boiler and a photograph of the probe in “Location B” are shown in Figure 5.

Figure 5 - Field testing of an electrochemical corrosion monitoring system

During this field test the monitoring system was initially installed with the sensor probe located in an existing port through an alcove in the windbox (the ductwork used to carry heated combustion air). This port is roughly ten feet above the upper row of burners. Subsequently, the probe was removed and inserted into a second existing port located just above the windbox [17]. Following a brief shakedown period, the system was used without incident under harsh conditions including the high ambient temperatures within the windbox alcove and a brief outage during which the waterwalls (and probe) were cleaned with highpressure water. Qualitative comparisons between the indicated corrosion rate and the operating conditions within the boiler resulted in clear, often near-instantaneous, responses. In general, as load increased, corrosion rate also increased. This is consistent with the sulphur-deposition-based mechanism referred to previously. Figure 6 presents a sample of data collected over a 24hour period. Although the bulk of the data, collected over a period of roughly 9 weeks in two locations, indicated a clear relationship between load and corrosion, a causal relationship was more

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difficult to identify with certainty because operating conditions other than firing rate also vary with load.

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Figure 6 - Real-time corrosion rate data compared to historical plant data (from the Plant Information or PITM System) For example, excess air, certainly an important factor in waterwall corrosion, typically increases at lower loads. However, constant load tests over 24 hour periods at excess O2 levels from 2.4 to 3.0 percent resulted in very similar average corrosion rates [12] and displayed no indication of increasing corrosion at the lower oxygen concentration. In addition, there other evidence to supported the deposition-based mechanism: •

Periods of high heat flux, as determined by large temperature gradients across the sensor elements, corresponded to periods of noticeably higher corrosion.

•

Significantly higher average rates of corrosion were recorded at probe location “B,” which displayed a greater accumulation of deposited material. Figure 7 compares the corrosion rate data and probe face photographs (immediately following removal) corresponding to the two different probe locations.

An additional feature of Figure 7 worth noting is that the one period (near the middle of the test), where boiler load is high and corrosion rate is relatively low, corresponded to a period of unusually low heat flux detected during the test.

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Figure 7 - Real-time corrosion rate data over roughly two-week periods and photographs of the resulting probe face deposition

Qualitatively, the field test results were consistent. The response of the system to changes in boiler operating conditions and probe sensor temperature was logical and highly sensitive. Subsequent installations may incorporate modifications of the hardware and evolution of the software, but the sensor, control hardware, electronics, and computational hardware/software were reliable and generally robust. However, another key element of the field tests involved evaluating the quantitative accuracy of the corrosion rate indication. SURFACE PROFILOMETRY Techniques for quantitative measurement of material corrosion are available in the form of corrosion “coupons.” However, as discussed previously, this technique typically requires time periods ranging from weeks to months. In order to provide a direct measurement for comparison/validation of the electrochemical approach used herein, a new approach to corrosion coupons was required. The goal was to perform tests over short periods of time during which the conditions and resulting corrosion rates varied little. This made it possible to evaluate the accuracy of the electrochemical technique over a range of conditions. The technique developed involved the use of specially prepared sensor elements, which includes a corrosion resistant border to identify the uncorroded surface plane. Corrosion tests of a

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predetermined duration were performed for a specific set of conditions. The sensor was then disassembled and the electrodes were cleaned with a soft brush to remove loose solids from the surface, and was then immersed in Clarke’s solution, according to ASTM G1-81 7.7.2 to remove residual corrosion products. After the cleaning, the plates were again characterised using the profilometer. Figure 8 shows the profilometer scans of a sensor element after a 72hour exposure to a moist gaseous environment containing 2100 ppm HCl and 100 ppm CO at 500°C.

Figure 8. Surface profile of a corroded sensor element showing the inert reference border at the left and right hand side edges The profilometer data was processed with in-house software that determined the volume of material removed and this was compared directy with the integral of the calculated electrochemical corrosion rate over the test period. The approach had very high resolution and was be performed on sensor elements that had been exposed for periods as brief as 8 hours (or one shift at the plant). Uncertainties involved in this comparison include the removal of corrosion product, a possibility of unequal corrosion between the three sensor elements involved (though they were clearly very close together during the exposure period), and the effects of signal averaging. However, applying this technique during two test periods in the field and three test periods under less corrosive conditions in the laboratory, the results were very promising, as is illustrated in Figure 9.

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L- Laboratory test in 100 MBtu/hr furnace F5- Field test in 680 MW Coal-fired Boiler (5th floor) F7 - Field test in 680 MW Coal-fired Boiler (7th floor)

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Figure 9 - Comparison of the average depth of material removed as indicated by electrochemical signals and by direct physical measurement

CONCLUSIONS The complex relationship between corrosion and fuel properties, firing systems, and operating conditions in a coal-fired boiler can make it difficult to predict, diagnose, and manage waterwall wastage. It is therefore important to apply tools that can bring close focus and control to future boiler operation. The results of recent investigations demonstrate that the combination of CFD with real-time sensing technology has the capability to improve the precision of control and reduce unforeseen or unexpected corrosion risk. Application of these tools will vary based according to the needs of a particular situation, but their use could include the following: •

Real-time management of corrosion risk in the radiant section and superheater sections of power generation boilers.

•

Short-term evaluation of available fuel characteristics, deposit analyses, tube temperature measurements, and heat flux measurements to identify and avoid corrosion damage in boilers, furnaces, heaters and other types of combustion plant.

•

Predictive off-line CFD simulations of the boiler combustion characteristics over a range of relevant fuel/load/environmental conditions. 12

•

Correlation of CFD predictions with plant observables, including flue gas analyses, tube maintenance history, and tube wall ultrasonic test data to refine model inputs and accuracy, and to identify potential trouble spots and key fuel properties, combustion modifications (i.e. LNBS and OFA), and desirable operating regimes.

•

Use of real-time monitoring and CFD modelling to investigate, characterise and avoid the causes of specific negative plant service life experience.

•

Validation of the quantitative accuracy of on-line techniques by means of precision metrology.

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Use of CFD modelling to develop guidelines for optimising the boiler operation, based on plant-specific considerations including NOx emissions, carbon-in-flyash, and waterwall wastage.

ACKNOWLEDGEMENTS The corrosion-specific CFD model development was funded by EPRI with technical guidance from and under the supervision of Wate Bakker and Tony Facchiano. The fundamental development aspects of this program were funded by the Department of Energy /NETL through contract DE-FC26-00NT40753 under the supervision of Bruce Lani and Soung-Sik Kim. The formal field-testing was funded by the Ohio Coal Development Office through contract CDO/D-99-12 under the supervision of Howard Johnson. Field test support was provided by FirstEnergy under the direction of Robert Walters. REFERENCES 1

Syrett, B. C. and Gorman, J. A., “Cost of Corrosion in the Electric Power Industry – An Update”, Materials Performance, 42 (2), 32-38, 2003.

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Bockelie, M. J., Adams, B. R., Cremer, M. A., Davis, K. A., Eddings, E. G., Valentine, J. R., Smith, P. J. and Heap, M. P. PVP-Vol. 377-2, “Computational Simulations of Industrial Furnaces,” Computational Technologies for Fluid/Thermal/Chemical Systems with Industrial Applications, ASME, pp 117-124, 1998.

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Crowe, C. T., Sharma, M. D., and Stock, D. E., The Particle-Source-in-Cell (PSICell) Model for Gas-Droplet Flows. J. Fluids Eng. 99, 325-332 (1977).

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Kung S. Prediction of Corrosion Rate for Alloys Exposed to Reducing/Sulphidising Combustion Gases. NACE Conference on Corrosion '97. March, 97-136, (1997).

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Nava, J., and Plumley, A., Wastage control in low emission boiler system. 3rd Int’l Conference on Boiler Tube Failures in Fossil Plants, Nashville, TN, November, (1997).

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James, P. J., and Pinder, L. W., “Effect of coal chlorine on the fireside corrosion of boiler furnace wall and superheater/reheater tubing”, Materials at High Temperatures, 14, (3), 187-196, (1997).

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Nielsen, H. P., Frandsen, F. J., Dam-Johansen, K., and Baxter, L. L., “The implications of chlorine-associated corrosion on the operation of biomass-fired boilers”, Prog.Energy Combust. Sci., 26, 283-298, (2000).

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Davis, C. J., James, P. J., Pinder, L. W., and 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, Park City, Utah, May (2000).

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Kung, S. C., and Bakker, W. T., “Waterwall Corrosion in Coal-Fired Boilers-a New Culprit: FeS”, NACE Corrosion 2000, March, Orlando, Florida, 26-31, (2000).

10 Srinivasachar, S., Boni, A., “A kinetic model for pyrite transformations in a combustion environment”, Fuel, 68, 829-836, (1989). 11 Valentine, J., Davis, K., Adams, B., Heap, M., Bakker, W., “Modeling potential waterwall wastage based on pyritic deposition and wall conditions”, United Engineering Foundation Conference on Effects of Coal Quality on Power Plant Management: Ash Problems, Management and Solutions, Park City, Utah, May (2000). 12 Davis, K., Dissel, A., Valentine, J., “The evolution of pyritic and organic sulfur from pulverised coal particles during combustion”, The 2nd Joint Meeting of the US Sections of the Combustion Institute, Oakland, CA, March (2001). 13 Bakker, W. T., Mok, W. Y., and Cox, W. M., “High-Temperature Fireside Corrosion Monitoring in the Superheater Section of a Pulverised-Coal-Fired Boiler”, EPRI, Palo Alto, CA: 1992, TR-101799. 14 Kane, R. D., and Cayard, M. S., “Use Corrosion Monitoring to Minimise Downtime and Equipment Failures”, Chemical Engineering Progress, October, 49-57, (1998). 15 Davis, K., Lee, C., Seeley, R., Harding, S., Heap, M., Cox, W., “Waterwall corrosion evaluation in coal-fired boilers using electrochemical measurements”, 25th International Technical Conference on Coal Utilization & Fuel Systems, Clearwater, FL, March (2000). 16 Harb, J. N., and Smith, E. E., “Fireside Corrosion in PC-Fired Boilers”, Prog. Energy Combust. Sci., 16, 169-190, (1990). 17 Linjewile, T., Davis, K., Green, G., Cox, W., Carr, R., Harding, S., Overacker, D., “On-Line Technique for Corrosion Characterization in Utility Boilers”, Effects of Coal Quality on Power Plant Management, United Engineering Foundation, Snowbird, Utah, October (2001).

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FIGURE CAPTIONS Figure 1 - Corrosion rate as a function of tube temperature and H2S concentration, as predicted by an existing correlation [4] Figure 2 - Figure 2. Sulphur release during coal char oxidation [12] Figure 3 - Field measurements and CFD-based predictions of waterwall wastage

Figure 4 - Corrosion rate responding to changes in combustion stoichiometry

Figure 5 - Field testing of an electrochemical corrosion monitoring system

Figure 6 - Real-time corrosion rate data compared to historical plant data (from the Plant Information or PI System)

Figure 7 - Real-time corrosion rate data over roughly two week periods and photographs of the resulting probe face deposition

Figure 8 - Surface profile of a corroded sensor element showing the inert reference border at the left and right hand side edges

Figure 9 - Comparison of the average depth of material removed as indicated by electrochemical signals and by direct physical measurement

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