The project focused on advancing electrochemical measurement techniques for high‑temperature corrosion in power plant boiler tubes. A key objective was to refine the existing membrane‑wall sensor so that it could deliver a quantitative corrosion rate expressed in millimetres per year (mm / a). By redesigning the electrode geometry, the team achieved an approximate four‑fold improvement in signal resolution. Corrosion coupons were used to determine the actual material loss, enabling calibration of the sensor signal and the conversion of the measured current density (A / m²) into a user‑friendly mm / a value. This quantitative output is considered essential for plant operators, who find current density units difficult to interpret.
The project also evaluated a range of commercial Linear Polarization Resistance (LPR) transmitters. Electrochemical impedance spectroscopy was employed to compare the performance of different transmitter designs, allowing the selection of the most suitable electronics for field deployment. In the laboratory, a custom high‑temperature furnace was used to investigate how alternating oxidising and reducing gas atmospheres—typical of flexible plant operation—affect the sensor signal. The results showed that the corrosion signal drops to a baseline after the plant is shut down, then rises sharply when the temperature falls below a critical threshold, suggesting that condensation of acidic, hygroscopic gas components drives the observed corrosion spikes.
Large‑scale field tests were carried out in the Lippendorf power plant. Twelve sensors, all fabricated with the improved V2a geometry, were installed at heights ranging from 19.5 m to 45.5 m using a precision drilling template. The installation was completed during a plant shutdown, and data acquisition began on 8 September 2020. Over a five‑month period, the sensors recorded distinct signal patterns depending on their location relative to the burners. Sensors above the burners displayed continuous, low‑volatility signals, while those below showed slightly lower average corrosion rates but higher volatility. No long‑term trend was observed during the monitoring window, but intermittent intervals of elevated signals coincided with temperature excursions, reinforcing the link between thermal cycling, condensation, and corrosion.
The sensor data were complemented by profilometric surface analysis of the coupons, which confirmed the real material loss and validated the calibration procedure. The project envisaged extending the monitoring network to multiple power plants, with the goal of mapping corrosion spatially and temporally and correlating it with operational parameters. The planned 12‑month measurement campaign would provide statistically robust data for further refinement of the sensor technology.
The research was carried out by a consortium of academic and industrial partners, each contributing distinct expertise. Design and laboratory testing were led by the university’s corrosion research group, while the industrial partners supplied the commercial transmitters and facilitated the installation in the power plant. Data analysis and interpretation were performed jointly, with the plant operators providing operational context and access to plant parameters. The field deployment began in 2020, and the project has continued to collect data for up to a year, with ongoing plans for broader implementation. No specific funding agency is mentioned in the report, but the project’s scope and duration suggest support from a national research programme or industry‑driven initiative.