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Online measurements of fireside high temperature corrosion in power plants VGB PowerTech 12 l 2016

Authors

Kurzfassung

Weiterentwicklung von Messsystemen zur Online-Messung rauchgasseitiger Korrosion an Verdampferwänden

Am Institut für Energiesysteme und Energie-technik der TU Darmstadt werden Korrosions-messsysteme für den Einsatz im Verdampferbe-reich von braun- und steinkohlegefeuerten Kraftwerksanlagen entwickelt. Mittels elektro-chemischer Messverfahren wird die rauchgas-seitige Hochtemperaturkorrosion ermittelt, wodurch der Korrosionsangriff zeitaufgelöst dargestellt wird. Eine wesentliche Weiterent-wicklung ist der Einsatz sogenannter Membran-wandsensoren, welche an beliebiger Stelle in den Stegen der Membranwände eingebaut wer-den können und durch diese passiv gekühlt wer-den. Zur Qualifizierung der Messtechnik für den Kraftwerkseinsatz wurden verschiedene Tests in Laboreinrichtungen durchgeführt, bei denen Korrosionsmessungen unter realen Be-dingungen durchgeführt wurden. Insbesondere Tests mit synthetischen Rauchgasen zeigen hier-bei eine hohe Sensitivität bezüglich H2S als kor-rosiver Gasbestandteil. Weiterhin wurden Mes-sungen in zwei Kraftwerksanlagen durchge-führt, wobei sich eine Anlage mit hoher Korrosionsbelastung und die andere Anlage mit geringer Korrosionsbelastung auszeichnen. Dementsprechend wurden hohe bzw. geringe Korrosionssignale in den jeweiligen Anlagen ge-messen. l

* For his outstanding research and results, Josef Langen was awarded with the “VGB Innova­tion Award 2016” by the VGB FORSCHUNGS­STUFTUNG.

Online measurements of fireside high temperature corrosion in power plants with membrane wall sensorsJosef Langen, Andreas Müller, Jochen Ströhle and Bernd Epple

M.Sc. Josef LangenM.Sc. Andreas MüllerDr.-Ing. Jochen StröhleProf. Dr.-Ing. Bernd EppleInstitute for Energy Systems and Technology, TU Darmstadt, Darmstadt/ Germany

Introduction

In power plants high temperature corro­sion occurs at the fireside of steam genera­tors due to the combustion. The intensity of the corrosion attack depends on several factors and varies with changing operating mode of plant operation. The fuel proper­ties, especially the sulphur and chlorine contents, have a significant influence on the corrosion behaviour. A switch to differ­ent coal qualities or co­combustion of sec­ondary fuels such as waste or sewage sludge can lead to high corrosion rates with rapid material loss. Especially the lower parts of combustion chambers that are op­erated at substoichiometric conditions for NOx reduction are affected by different coal properties due to the formation of cor­rosive gases like H2S or HCl. Another as­pect is the influence of the volatile grid feed­in of renewable energies on the plants operation mode. Due to load changes, some areas of a steam generator are ex­posed to alternating oxidising or reducing atmospheres. A frequently change of oxi­dising and reducing atmospheres can lead to increased corrosion rates in these af­fected areas.For these reasons, steam generators are ex­posed to permanent fluctuating conditions that generate permanent changing corro­sion intensities of boiler tubes. By using corrosion monitoring techniques, periods with increased corrosion intensity can be detected. With the exact time of increased corrosion rates, an investigation on rea­sons for increased corrosion attack is pos­sible, and specific countermeasures can be applied. Furthermore, online corrosion measurements are a helpful tool for life­time monitoring. By means of corrosion monitoring, inspection downtimes can be planned to check, repair or protect corrod­ed areas.At the Institute for Energy Systems and Technology online corrosion measurement systems are developed especially for corro­sion measurements at membrane walls of power plants. The measurement system, consisting of corrosion probe, measure­ment electronics and data acquisition, is designed for long­term measurements at rough conditions at the outer side of steam generators like high ambient temperatures,

dust or splash water. A particular focus was on development of a passively cooled cor­rosion sensor which enables measure­ments with low maintenance effort.

Electrochemical measurement technique

The various corrosion mechanisms that oc­cur at the fireside of boiler tubes are mainly electrochemical reactions. This enables the application of electrochemical measure­ment techniques. At electrochemical reac­tions, the corrosion attack occurs in combi­nation with an electrolyte [1]. In steam generators fired with solid fuels, deposits act as a solid electrolyte with a sufficient electrolytic conductivity.Due to the contact of electrolyte and metal surface of boiler tubes, anodic and cathod­ic partial reactions occur in which charge carriers (electrons and ions) exchange through the metal­electrolyte interface. This transfer generates a potential which is called corrosion potential Ecorr The charge transfer from metal to electrolyte is charac­terised by cathodic partial current Ic and the charge transfer from electrolyte to met­al is characterised by anodic partial current Ia At the corrosion potential Ecorr, the abso­lute values of anodic and cathodic partial currents equals each other, so that the re­sidual current is Ires= 0. By relating the cur­rents to the surface, they are named cur­rent densities ires, ia and ic. By applying a voltage, the corrosion potential is shifted, and a residual current is measurable. The shift of the corrosion potential is called po­larisation, and the applied potential is called overpotential η. In the vicinity of the corrosion potential, the residual current density is a linear function of the applied overvoltage (F i g u r e 1 , left). The ratio of overvoltage and residual current is called linear polarisation resistance RP [2]. In F i g u r e 1 (left) the current density is qual­itatively shown as a function of the overpo­tential. At high overpotentials, the current is limited by diffusion controlled mass transfer of ions at the metal­electrolyte in­terface. The anodic and cathodic partial current densities at the corrosion potential are a degree for the intensity of redox reactions and hence a degree for the corrosion inten­

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VGB PowerTech 12 l 2016 Online measurements of fireside high temperature corrosion in power plants

sity. At the corrosion potential, the partial current densities are called exchange cur­rent density icorr. The exchange current density cannot be measured directly, only the residual current density is measurable. By neglecting the limiting diffusion con­trolled mass transfer at high overpotentials, the residual current can be described by Butler­Volmer equation as a function of ex­change current density and overpotential. In F i g u r e 1 (right) the slope of the cur­rent density­overpotential characteristic is shown qualitatively in accordance with Butler­Volmer equation in a semi­logarith­mic scale and absolute values for negative overpotentials. By means of the Stern­Geary equation, the exchange current den­sity can be determined as a function of the linear polarisation resistance RP:

(1)

Herein the B­value (or Stern­Geary con­stant) is calculated by Tafel-coefficients ba and bc. The Tafel-coefficients describe the gradient of the linear section in the semi­logarithmic current density­overpotential characteristic. In accordance with Stern­Geary equation the exchange current den­sity is the intersection of the Tafel­slopes and the ordinate (F i g u r e 1 , right) [3]. The B-value is a material specific value and can be chosen from literature or deter­mined by measurements.To determine the linear polarisation resist­ance, a measuring method basing on elec­trochemical impedance spectroscopy is used. Herein, the metal­electrolyte inter­face is described by an electrical circuit consisting of linear polarisation resistance, electrolyte resistance and double layer ca­pacitor. Electrolyte and linear polarisation resistance can be determined by perform­ing several impedance measurements with different voltage frequencies [4].

Corrosion measuring probes for membrane walls

To apply electrochemical measurement techniques, measuring probes are needed which are exposed to the same conditions as boiler tubes at the fire side. The previ­

ously described measurement technique requires three electrodes that are covered with deposits during operation. The elec­trodes are manufactured from the same material of boiler tubes and have to be elec­trically insulated from each other. Further­more, the measuring probes have to be cooled so that the electrode temperature equals the membrane wall temperature.In the past, water­cooled measuring probes were used with electrodes shaped as a third of a disk (F i g u r e 2 , left). The elec­trodes are electrically insulated by a ceram­ic insulator from each other and are fixed on a probe head. The probe head is mount­ed on a cooling lance by which the measur­ing probe is inserted into the furnace (F i g ­u r e 2 , right). The corrosion probe can be installed at existing ports like boiler hatch­es or flanged apertures. The cooling lance is connected to a water cooling circuit to adjust the measuring probe to the desired material temperature. This type of corro­sion measuring probe was successfully tested and several measurements were per­formed in lignite and hard coal fired power plants since 2008 [5].A new concept of passively cooled measur­ing probes was developed to reduce the complexity of corrosion measurement sys­tems. The newly developed membrane wall sensor consists of three square shaped electrodes that are attached to a ceramic insulator. The width of the ceramic insula­tor is 10 mm so that the insulator can be placed at the web of a tube­web­tube sec­tion. Therefore, a slot has to be cut into the web through which the electrodes can be inserted into the furnace (F i g u r e 3 , mid­

dle). The insulator is fixed by a mounting support which is screwed on the outer side of the membrane wall (F i g u r e 3 , left). The chosen materials of insulator and mounting support as well as the geometry of the components ensure a sufficient heat transfer between measuring probe and membrane wall. By this arrangement the measuring probe is passively cooled by the membrane wall so that an additional cool­ing system is not needed. Furthermore, the installation of the measuring probe does not rely on existing ports, which enables a flexible application in arbitrary positions of membrane walls. The installation lasts 2­3 hours per measuring probe and can be done from the outer side of the boiler so that no scaffolding work is necessary at the inner side of the boiler. After the installa­tion of a membrane wall sensor, the area around the measuring location is covered with boiler insulation again. The measur­ing electronic to which the measuring probe is wired and the measuring data re­cording device are located in a control cab­inet (F i g u r e 3 , right). The measuring data can also be integrated in the existing control system of the power plant.

Lab-scale investigations

Various lab­scale tests were performed to qualify the measuring probes for measure­ments in power plants. These tests were done in an entrained flow reactor and a chamber furnace. In the entrained flow re­actor, a measuring probe is exposed to the combustion of different fuels. Here the in­fluence of different fuel properties and air ratios on the corrosion behaviour was in­vestigated. In the chamber furnace, corro­sion measurements with defined gas com­positions and different deposits were per­formed.

Entrained Flow reactorIn the entrained flow reactor, combustion experiments with different solid fuels were performed with well-defined experimental conditions like combustion temperature or air ratio. The combustion chamber is a ce­ramic tube with an inner diameter of 70 mm and a length of 2.2 m (F i g u r e 4 ). The fuel is fed into a water cooled injector lance and is transported pneumatically

Residual current density

Curr

ent d

ensit

y i

Potential

icorr

ires

ic

ia

η

-η η

log

|i|

log |icorr|

babc

Ecorr

Ecorr

Fig. 1. Left: current density-potential characteristic, right: current density-overpotential characteristic according to Butler-Volmer equation [2].

Fig. 2. Left: water-cooled measuring probe, right: cooling lance installed at steam generator.

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Online measurements of fireside high temperature corrosion in power plants VGB PowerTech 12 l 2016

with primary air to the combustion cham­ber. Here the combustion takes place with additional preheated secondary air. From the bottom a water­cooled lance can be in­serted into the reaction tube. On the tip of the lance, a measuring probe was mounted and exposed to the combustion. The reac­tion tube is electrically heated by heating elements which are circularly arranged around the reaction tube. The reactor can be operated at temperatures between 900 and 1,600°C. A gas analysis is connected to lateral measuring ports to determine the gas composition and to control the com­bustion.

Chamber furnaceIn the chamber furnace, corrosion meas­urements with synthetic flue gas were per­formed. The newly developed membrane wall sensors are installed on a water­cooled rack that is inserted from the bottom into the furnace (F i g u r e 5 ). Before the meas­uring probes are inserted into the furnace, the electrodes have to be covered with de­posits. The synthetic flue gas is mixed with

CO2, CO, N2, Air, SO2 (in N2) and H2S (in N2) in various concentrations. Distilled wa­ter is pumped by a dosing pump into an evaporator so that the desired H2O­con­centration can be introduced into the fur­nace. In operation, a small negative pres­sure is generated by an induced draft fan to prevent an escape of gas to the laboratory. The chamber furnace is heated electrically and can be operated up to 1,300 °C.

ResultsIn the entrained flow reactor, corrosion measurements were performed during the combustion of hard coal, dry lignite and torrified biomass. The electrodes of the

measuring probe were manufactured from 16Mo3 as a common boiler steel and were operated with a sensor temperature about 400 ro 450 °C. The combustion tempera­ture was 1,300 °C. The combustion experi­ments were performed with different stoi­chiometry at air ratios λ=0.8, λ=1.0 and λ=1.2. For each fuel and air ratio, several test series were performed and the ex­change current density as a value for the corrosion intensity was measured [6]. In F i g u r e 6 the average measured exchange current densities for each fuel and air ratio is shown. At λ=1.0 and λ=1.2, low ex­change current densities were measured indicating low corrosion intensities. At

Fig. 3. Installation of membrane wall sensor, left: outer side, middle: fireside, right: insulated measuring location and control cabinet.

Coal inlet

Downpipe

Preheater

Combustionchamber

Measuringprobe

Cooling lance

Heater

Measuringports

Fig. 4. Structure of the entrained flow reactor.

Gas mixer

Evaporator

Dosing pump

Heater

Exhaust

ID fan

Water-cooledrack

Measuringprobe

H2O

CO2, CO, N2, O2 H2S, ...

Fig. 5. Structure of the chamber furnace.

Dry lignite

Hard coal

Torref. biomass

0.84

0.650.74

0.16 0.140.19 0.14

0.09 0.12

1

0.8

0.6

0.4

0.2

0

Air ratio in ‐

i corr in

A/m

2

λ=0.8 λ=1.0 λ=1.2

Fig. 6. Average exchange current densities depending on stoichiometry [6].

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VGB PowerTech 12 l 2016 Online measurements of fireside high temperature corrosion in power plants

substoichiometric conditions, the corro­sion intensity is higher caused by reducing atmospheres and the formation of corro­sive gases like H2S or HCl. This increase was recorded by corrosion measurements with significant higher exchange current densities at λ=0.8.Additional test in the chamber furnace were performed to get further information about the sensitivity of the corrosion meas­urements. For the tests, a measuring probe with electrodes made from 13CrMo4­5 was used and operated at a temperature about 450 °C. The electrodes were covered with deposits obtained from an evaporator wall of a lignite fired power plant. The furnace temperature was 1,060 °C. A synthetic flue gas according to gas composition in Ta ­b l e   1 was introduced into the furnace in­cluding 600  ppm H2S as a corrosive gas. The flow rate was 500 l/h. The flue gas was introduced intermittently while the rest of the time nitrogen was introduced into the furnace.

Tab. 1. Gas composition of synthetic flue gas.

Gas composition

CO2 9.4 %

CO 7.3 %

N2 54.9 %

H2O 28.3 %

H2S 600 ppm

products which decelerates the diffusion of corrosive gases to the metal surface. This decrease of the reaction rate can also be explained by parabolic functions of lay­er growth (e.g. [7]) to which the integral of the exchange current density is compa­rable.After changing the atmosphere from syn­thetic flue gas to nitrogen, the exchange current densities decrease and return to the basic signal that marks conditions with no corrosion. The corrosion intensity is measured relative to the basic signal that amounts approximately 7 mA/m2. In other tests, corrosion measurements were per­formed with synthetic flue gas without H2S. Here no increase of corrosion signal was measureable so that the results can be assigned to the influence of H2S on the cor­rosion behaviour.

Experimental trial in power plants

The testing of the corrosion measurement system was performed in a lignite­ and a hard coal-fired power plant. The lignite-fired power plant has a capacity of 500 MWel at 535 °C/ 169 bar live steam and 540°C/  32 bar reheating. The measuring probe was installed at the lower part of the boiler nearby the burners. Due to the air staging the measuring probe was exposed to reducing atmospheres. The hard coal­fired power plant has a capacity of 510 MWel at 545 °C/ 262 bar live steam and 562 °C/ 55.4 bar reheating. The measuring probe was installed above the topmost burner level at oxidising atmospheres. In both power plants, measuring probes with electrodes made of 13CrMo4­5 were tested which were operated up to 420 °C in the lignite and up to 500 °C in the hard coal­fired power plant.According to information from the plant operators, the corrosion intensity in the hard coal-fired boiler is very low. In con­trast the corrosion intensity at the radia­tion section of the lignite-fired boiler is so high that the membrane walls were pro­tected by weld overlay in the past. These different corrosion intensities could be re­produced by the corrosion measurement system (F i g u r e 8 ). In the hard coal-fired

power plant an average current density of 7.7  mA/m2 was measured, which is mar­ginally higher than the basic signal of 7.0 mA/m2. In the lignite-fired power plant, significantly higher exchange current den­sities were measured with a mean value of 41.2 mA/m2.For further valuation of the corrosion sig­nal for practical applications, the corro­sion rate in millimetres per year should be given. A current issue of research and de­velopment is the correlation between ex­change current density and corrosion rate. At present, an empirical value for the correlation between exchange current density and corrosion rate is used so that 10 mA/m2 correspond to a corrosion rate of 0.52 mm/a. By this correlation, the ma­terial loss of the measuring probe can be estimated by the integral of the corrosion signal (F i g u r e 9 ). Therefore the materi­al loss during the measuring period amounts 0.589 mm with an average corro­sion rate of 1.79 mm/a for the lignite-fired power plant and <0.01 mm material loss with 0.036  mm/a corrosion rate for the hard coal-fired power plant, respectively.

Conclusion and outlook

Fireside high temperature corrosion of steam generators is time resolved measure­able by applying electrochemical corrosion measurement techniques. This enables the detection of periods of time with increased corrosion intensities by which targeted in­vestigations on reasons for increased corro­sion rates are possible. The new developed membrane wall sensor can be easily in­stalled in arbitrary positions of evaporator walls that enable a flexible application of corrosion measurements at evaporator walls. Furthermore, the application of membrane wall sensors reduces the effort for corrosion measurements compared to water­cooled measuring probes and ena­bles low­maintenance long­term measure­ments in power plants. The measurements in lab­scale test facilities and power plants verify the function of the measurement technique. Especially, tests with synthetic flue gas had shown a high sensitivity to small H2S­contents by which the decrease of the reaction rate was measureable. There­fore, the measurement technique is a help­ful tool for power plant operation to moni­tor the corrosion behavior of the boiler.An extensive application of several mem­brane wall sensors at evaporator wall is necessary to get further information of cor­rosion attack on boilers. This enables an additional locally resolved detection be­sides the time resolved detection of high temperature corrosion. Furthermore, the online measurements should be combined with offline measurements like coupons to get further information on the correlation between measured corrosion signal and ef­fective material loss.

Time in hh:mm

Flow

rate

n l/

h

i corr in

A/m

2

0.16

0.12

0.08

0.04

0.00

1,000

750

500

250

00:00 12:00 24:00 36:00 48:00 60:00 72:00 84:00

Fig. 7. Measured corrosion signal and flow rate of synthetic flue gas.

F i g u r e 7 shows the measured exchange current densities and the flow rate of the synthetic flue gas. By changing the atmos­phere from nitrogen to synthetic flue gas a clear increase of exchange current density is measurable. The complete exchange of the atmosphere and the diffusion of the flue gas through the deposit layer last ap­proximately two hours in which a continu­ous increase of exchange current densities is detectable. In the following periods in which the measuring probe is exposed to stationary conditions for each of the four phases, different corrosion intensities were measured with the highest corrosion inten­sity at the first and the lowest intensity at the fourth phase. This can be explained with the formation of a layer of corrosion

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Online measurements of fireside high temperature corrosion in power plants VGB PowerTech 12 l 2016

Acknowledgement

The development of corrosion measure­ment systems was researched within the project “Weiterentwicklung einer Online­Korrosionssonde und numerischer Mod­elle zur Messung bzw. Vorhersage der Hochtemperaturkorrosion an Heizflächen”

Time in d

i corr in

A/m

2

i corr in

A/m

2

Time in d

1.8

1.6

1.4

1.2

1

0.8

0.6

0.4

0.2

0

1.8

1.6

1.4

1.2

1

0.8

0.6

0.4

0.2

00 15 30 45 60 75 90 105 120 0 10 20 30 40 50 60 70 80

Fig. 8. Measured corrosion signal in lignite-fired power plant (left) and hard coal-fired power plant (right).

under grant agreement No. 03ET7023 funded by the Federal Ministry for Eco­nomic Affairs and Energy (BMWi). The au­thors would like to thank the BMWi and all participating industrial partners: Babcock Borsig Steinmüller, Engie, GE Power, MHPSE, RWE Power, Salzgitter Mannes­mann Forschung, STEAG, Uniper Kraft­

Mat

eria

l los

s in

mm

Time in d

0.7

0.6

0.5

0.4

0.3

0.2

0.1

00 15 30 45 60 75 90 105 120

Fig. 9. Material loss of the measuring probes at the lignite-fired power plant.

werke, Vallourec Deutschland and Vatten­fall Europe Generation for their technical and financial support.

References[1] Hamann, C.H., and Vielstich, W.: Elektroche-

mie. Weinheim: Wiley­VCH, 1998.[2] Bard, A.J., and Faulkner, L.R.: Electrochemi-

cal methods: fundamentals and applications (Vol. 2). New York: Wiley, 1980.

[3] Stern, M., and Geary, A.L.: Electrochemical polarization I. A theoretical analysis of the shape of polarization curves. Journal of The Electrochemical Society 1957, 104(1): 56­63.

[4] Rammelt, U.: Die elektrochemische Impe-danzspektroskopie in der Korrosionsfor-schung. Habilitation, TU Dresden, 1991.

[5] Zorbach, I.S.: Entwicklung einer Sonde zur Online-Messung von Verdampferwandkorro-sion. Dissertation, EST – TU Darmstadt, 2013.

[6] Langen, J., Ströhle, J., and Epple, B.: Weiter-entwickelung von Korrosionsmesssystemen zur Online-Messung rauchgasseitiger Ver-dampferwandkorrosion. VDI­Berichte 2016, 2267:195­205.

[7] Mrowec, S.: Mechanism of high-temperature sulphide corrosion of metals and alloys. Mate-rials and Corrosion 1980, 31(5):371­386. l

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