Corrosion Woburn

8/6/2019 Corrosion Woburn

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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. CoxCorrosion Management

ABSTRACT

Combustion modifications to minimise NOx emissions have led to the existence of reducingconditions 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 increasedcorrosion that can occur on wall tubes exposed to fuel rich combustion environments.Current boiler corrosion monitoring techniques rely on ultrasonic tube wall thicknessmeasurements 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 informationis obtained after the damage has been done. Management of boiler waterwall loss and systemoptimisation therefore requires a real-time indication of corrosion rate in susceptible regionsof the furnace. This paper describes the results of a program of laboratory trials and fieldinvestigations and considers the use of an on-line technology in combination with innovativeapplications 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 flameimpingement 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. Inutility boilers, for example, staging has increased the frequency and severity of waterwallwastage, 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 featuresincluding fuel selection, tube temperature, and firing system design. Formulating solutions to

this problem can be complicated by the range of potential corrosion mechanisms, which caninvolve gas-phase sulphur and/or chlorine in addition to the direct deposition of unreactedfuel. The physics and chemistry controlling corrosion processes can be highly non-linear.



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Therefore, brief periods of exposure to unusual conditions can dominate the overall materialloss between inspections. Due to the complex relationships between corrosion and itscontrolling factors, in addition to the difficulty in assigning periods of high corrosion tospecific operational factors, the ability to understand, monitor, and manage boiler waterwallloss could be dramatically improved through the application of predictive modellingtechniques 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 beendeveloped.

On-line high-temperature corrosion monitoring is also a developing technology. Anevaluation of existing technologies revealed that no real-time monitoring options had

achieved industry-wide acceptance. It was important, therefore, for any monitoringtechnology used to be verified against physical measurements during a period of stableoperation. As boilers are rarely operated in a stable manner for an extended period (e.g. dueto load variation, fuel property variation, and operator tendencies), it was considered usefulthat 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 fieldinstrumentation to use in a complementary approach to corrosion management. Thefollowing sections detail progress in these three areas, i.e. CFD modelling, electrochemicalmonitoring 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 tomodelling the fate of fuel/ash particles provided a convenient basis for implementingdescriptions of phenomena such as deposition and corrosion. The mean path and dispersionof an ensemble of particles, referred to as a “particle cloud,” were tracked in a Lagrangianreference frame. Dispersion of the cloud was determined with input from the turbulent gasflow field. Particle mass, momentum, and energy sources were coupled to the gas flow fieldthrough a particle-source-in-cell technique [3]. Particle reaction processes included coaldevolatilisation, char oxidation, and liquid evaporation. Waterwall deposition was accountedfor by evaluating particle/wall interactions.

Corrosion rates in a boiler can be predicted using GLACIER in conjunction with empiricalcorrelations relating corrosion rates with predicted properties of the boiler. Although the

mechanisms responsible for the corrosion of furnace waterwall tubes are not generally agreedupon, 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 correlationswere developed for each of these mechanisms. In addition Reaction EngineeringInternational 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 effectivelydemonstrate their usefulness based on field observations.

Hydrogen Sulphide

The presence of reduced sulphur species near furnace waterwalls is known to result in tube

metal corrosion. Correlations based on laboratory experiments were developed relatingcorrosion rates to tube temperature, steel composition, and H2S concentration [4, 5]. Byimplementing one such correlation [4] into a post-processor for use with GLACIER, localcorrosion rates may be estimated for coal-fired boilers. The correlation requires localinformation regarding tube temperature and H2S concentration as well as the weight %chromium of the tube material. Recent studies have shown that this gas-phase mechanismtends 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 thehigh end of the range encountered in coal-fired boilers, the corrosion rates from gas-phase

sulphur attack are limited.

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 beenretrofitted 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 possibleexplanation for this behaviour [9]. Providing a detailed description of the sulphur-containingmaterial depositing on waterwalls requires more than a simple description of fuel pyrolysisand oxidation. For example, fuel-sulphur can exist in multiple forms including pyritic,organic and sulphatic forms. In addition, during pulverisation, much of the pyritic fractioncan 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 resultin particle trajectories that vary from the bulk coal. In order to more accurately model thetransport and deposition of sulphur within a coal-fired boiler, the following steps can betaken:

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

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

The thermal decomposition and oxidation of excluded pyrite has been studied in detail andthe model of Srinivasachar and Boni [10] was the basis for the approach implemented in

GLACIER [11]. CCSEM analyses can be

used to define the size of the pyrite particles and the amount inexcluded/included form. Although theevolution of pyritic and organic sulphur from within the coal matrix is not well

understood, a complementary lab-scalestudy [12] has provided insight for thedetailed modelling approach. This studyof four coals suggested that organicsulphur was released in proportionsroughly equivalent to that of the bulk coalas illustrated in Figure 2. However,sulphur from pyrite, while also released ina nearly proportional manner during

oxidation, was preferentially releasedduring pyrolysis. The extent of pyritedecomposition 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 laboratorystudies to quantify the impact of sulphur deposition on waterwall wastage, corrosion ratecorrelations have been developed and evaluated using several test cases. In general termsthis 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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Figure 2. Sulfur release during coal char oxidation [12]



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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 beapplied 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 manyyears. The experience in the UK power industry has been documented in several studies atvarious scales [6] and the impact of chlorine in corrosion processes within waste boilers iswell recognised. Further, the potential for chlorine-associated corrosion in biomass-fired

boilers has recently been investigated by Nielsen et al. [7]. However, the mechanism bywhich this corrosion process occurs and the conditions under which chlorine plays animportant role within coal-fired boilers are not established. Recently, efforts have been madeto reconcile conflicting conclusions in this area and to focus on quantitative correlations

under relevant conditions [8]. These correlations, which involve coal chlorine content, heatflux, and tube temperature, were added to the corrosion predictor model and evaluatedthrough 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 corrosionindicated 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 requiresreal-time measurements. Serious tube damage can occur in relatively brief time frames dueto a number of potential irregularities that can be difficult to identify from control

Front WallRear Wall

(max = 0.65 mm/yr) (max = 2.35 mm/yr)

Side Wall Center Wall

(max = 0.73 mm/yr)(max = 2 mm/yr)

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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 candetect the overall contribution of such effects on the relative corrosivity of the combustiongas to the tube material allows the damaging conditions to be recognised and addressedimmediately. Real time sensing complements CFD modelling in other ways; hightemperature corrosion mechanisms in coal-fired boilers are not well understood and the

robustness of the available empirical correlations is not well known. At best suchcorrelations should be considered only to be semi-quantitative in nature. In addition, it isoften difficult to develop a complete and accurate description of the various inputs for amodel of a coal-fired boiler (e.g., fuel and air distribution, wall deposition conditions). A realtime electrochemical sensor therefore can provide important verification of the validity of theinput description, and a ‘safety net’ if unanticipated or undisclosed circumstances – such asan unexpected change in fuel supply source – place the boiler at risk.

Monitoring high temperature corrosion in a reliable, effective, and timely manner is achallenging task. Techniques that have been effective for identifying corrosion after-the-factinclude visual inspection and ultrasonic tube-thickness measurement. Under conventionalcombustion 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 duringscheduled outages. However, as a result of the widespread introduction of reducingcombustion conditions for NOx control, and the increased time between scheduled outages,costly tube failures due to waterwall corrosion have become more common. Retrospectivedamage quantification techniques provide little insight into the causes of corrosion and makeit difficult to do much more than repair the damage, often during forced outages. Corrosioncoupons could be used to evaluate corrosion rates between outages, and additional analysesmay provide some understanding of a particular mechanism involved. However, accuratecontrol of the operating temperature of such coupons is difficult and the results of coupontests are notoriously unreliable. Corrosion damage may occur over a period of severalmonths 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 scanningmicroscopy, 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 onelectrochemical sensing was utilised, The system comprised a temperature-controlledelectrochemical sensor, signal conditioning and data acquisition modules, a temperaturecontroller, cooling air supply and a computer for data processing. The instrumentation dataacquisition modules and temperature controller were enclosed in a rugged dust-free metalenclosure. 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 areconverted to a digital signals and supplied to a computerised data acquisition unit. Anestimate of the rate of corrosion, I Corr ,, is obtained by replacing the polarisation resistance(R p) in the standard Stern-Geary equation and converting the corrosion current value soobtained to an equivalent metal loss rate by application of Faraday’s Law [13]:



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n

Corr R

B I =

where B is the Stern-Geary coefficient.

Corrosion rate is computed as a product of the corrosion current density and the materialconstant. 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 (2electrons 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 monitoringtechnologies, which have been used successfully in low temperature applications, and exploittheir usefulness in higher temperature combustion environments. Although these adaptationshave been successful in certain industries [14], the power industry has been slow to take upthe 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 combustionstoichiometry 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 from0.85 to 0.95. It is clear from the figure that the corrosion rate is influenced by combustionstoichiometry.

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. Harband Smith [16] report that reducing conditions are a consequence of poor combustionconditions resulting in low oxygen concentration, increased CO concentrations and the

presence of H2S.

Full-scale Plant Corrosion Tests

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

During this field test the monitoring system was initially installed with the sensor probelocated in an existing port through an alcove in the windbox (the ductwork used to carryheated 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 justabove the windbox [17]. Following a brief shakedown period, the system was used withoutincident under harsh conditions including the high ambient temperatures within the windboxalcove and a brief outage during which the waterwalls (and probe) were cleaned with high-

pressure water.

Qualitative comparisons between the indicated corrosion rate and the operating conditionswithin the boiler resulted in clear, often near-instantaneous, responses. In general, as loadincreased, corrosion rate also increased. This is consistent with the sulphur-deposition-basedmechanism referred to previously. Figure 6 presents a sample of data collected over a 24-hour 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

Figure 5 - Field testing of an electrochemical corrosion monitoring system



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

Figure 6 - Real-time corrosion rate data compared to historical plant data (from the PlantInformation 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] anddisplayed no indication of increasing corrosion at the lower oxygen concentration . Inaddition, there other evidence to supported the deposition-based mechanism:

• Periods of high heat flux, as determined by large temperature gradients across thesensor 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 thecorrosion 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 thetest), where boiler load is high and corrosion rate is relatively low, corresponded to a periodof unusually low heat flux detected during the test.

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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 thesoftware, but the sensor, control hardware, electronics, and computational hardware/softwarewere reliable and generally robust. However, another key element of the field tests involvedevaluating 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 requirestime 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 tocorrosion coupons was required. The goal was to perform tests over short periods of timeduring which the conditions and resulting corrosion rates varied little. This made it possibleto evaluate the accuracy of the electrochemical technique over a range of conditions. Thetechnique developed involved the use of specially prepared sensor elements, which includes acorrosion resistant border to identify the uncorroded surface plane. Corrosion tests of a

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



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predetermined duration were performed for a specific set of conditions. The sensor was thendisassembled and the electrodes were cleaned with a soft brush to remove loose solids fromthe surface, and was then immersed in Clarke’s solution, according to ASTM G1-81 7.7.2 toremove residual corrosion products. After the cleaning, the plates were again characterisedusing the profilometer. Figure 8 shows the profilometer scans of a sensor element after a 72-hour 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 atthe 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 calculatedelectrochemical corrosion rate over the test period. The approach had very high resolutionand was be performed on sensor elements that had been exposed for periods as brief as 8hours (or one shift at the plant). Uncertainties involved in this comparison include theremoval 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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CONCLUSIONS

The complex relationship between corrosion and fuel properties, firing systems, andoperating 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 focusand control to future boiler operation. The results of recent investigations demonstrate thatthe 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, buttheir 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, tubetemperature measurements, and heat flux measurements to identify and avoidcorrosion 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.

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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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F5- Field test in 680 MW Coal-fired Boiler (5th floor)

F7 - Field test in 680 MW Coal-fired Boiler (7th floor)

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



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• Correlation of CFD predictions with plant observables, including flue gas analyses,tube maintenance history, and tube wall ultrasonic test data to refine model inputs andaccuracy, and to identify potential trouble spots and key fuel properties, combustionmodifications (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 precisionmetrology.

• 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 technicalguidance from and under the supervision of Wate Bakker and Tony Facchiano. Thefundamental development aspects of this program were funded by the Department of Energy/NETL through contract DE-FC26-00NT40753 under the supervision of Bruce Lani andSoung-Sik Kim. The formal field-testing was funded by the Ohio Coal Development Officethrough contract CDO/D-99-12 under the supervision of Howard Johnson. Field test supportwas 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.

2 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, “ComputationalSimulations of Industrial Furnaces,” Computational Technologies for Fluid/Thermal/Chemical Systems with Industrial Applications, ASME, pp 117-124,1998.

3 Crowe, C. T., Sharma, M. D., and Stock, D. E., The Particle-Source-in-Cell (PSI-

Cell) Model for Gas-Droplet Flows. J. Fluids Eng. 99, 325-332 (1977).

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

5 Nava, J., and Plumley, A., Wastage control in low emission boiler system. 3

rd

Int’l Conference on Boiler Tube Failures in Fossil Plants, Nashville, TN, November,(1997).

6 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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7 Nielsen, H. P., Frandsen, F. J., Dam-Johansen, K., and Baxter, L. L., “Theimplications of chlorine-associated corrosion on the operation of biomass-fired

boilers”, Prog.Energy Combust. Sci., 26, 283-298, (2000).

8 Davis, C. J., James, P. J., Pinder, L. W., and Mehta, A. K., “Furnace Wall FiresideCorrosion in PF-Fired Boilers: The Riddle Resolved”, Presented at United

Engineering Foundation Conference on Effects of Coal Quality on Power PlantManagement: Ash Problems, Management and Solutions, Park City, Utah, May(2000).

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

10 Srinivasachar, S., Boni, A., “A kinetic model for pyrite transformations in a combus-

tion environment”, Fuel, 68, 829-836, (1989).

11 Valentine, J., Davis, K., Adams, B., Heap, M., Bakker, W., “Modeling potentialwaterwall 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 CorrosionMonitoring in the Superheater Section of a Pulverised-Coal-Fired Boiler”, EPRI, PaloAlto, CA: 1992, TR-101799.

14 Kane, R. D., and Cayard, M. S., “Use Corrosion Monitoring to Minimise Downtimeand 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 byelectrochemical signals and by direct physical measurement

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Corrosion Woburn