Steam-side Oxide Research Articles

Stress Analysis of the Steam-Side Oxide of Boiler Tubes: Contributions from Thermal Strain, Interface Roughness, Creep, and Oxide Growth

Stresses in the steam-side oxide of boiler tubes are evaluated based on analytical derivations and numerical simulations. With only thermal strain considered, analytical solutions of stress distribution are obtained for a cylindrical geometry representative of boiler tubes and a flat-plate geometry—a typical simplification assumed in the literature to represent boiler tubes with extremely thin oxide scale. In these analytical derivations, the substrate metal has finite dimensions or is assumed to be very thick. The solutions under the approximations of flat-plate geometry and very thick substrate are employed to examine the accuracy of various approximations adopted in the literature to analyze the stress distribution in boiler tubes. For more complicated situations where the contributions from thermal strain, interface roughness, creep of the oxide and metal, and oxide growth are considered, numerical simulations are performed for a cylindrical geometry to evaluate the stress distribution in boiler tubes. The simulation results reveal that: (1) the local radial stress at curved oxide–metal interfaces is enhanced by interface roughness with implications about interfacial crack growth; (2) contrary to the general belief that creep relieves the oxide stresses, creep may actually increase the stresses in the oxide due to different creep rates of the oxide and substrate metal; and (3) the geometrically induced oxide growth strain substantially increases the magnitudes of the hoop and axial stresses in the oxide. Based on the assumption that the failure of the oxide scales is caused by crack growth which is dominated by the stress intensity factor, damage maps are plotted directly using the hoop, axial, and radial stresses as the critical variables. Our work provides a quantitative understanding of the interactions between different thermomechanochemical processes and oxide scale failure in boiler tubes.

Measurement of Accumulated Height of Exfoliated Oxide Scales in Austenitic Boiler Tubes Using Pulsed Eddy Current Testing

Austenitic boiler tubes are key components in modern coal-fired power plants but often suffer from blockage or even rupture caused by the accumulation of steam-side oxide scales. Existing nondestructive testing methods are somewhat deficient to quantify the accumulated height of exfoliated oxide scales. Pulsed eddy current (PEC) technique has unique merits such as deep penetration depth and diverse signal features, offering a great possibility to address this issue. This work serves as an exploratory study for applying PEC technique to measure the scales accumulation. Finite element modeling and experimental work are conducted to validate the feasibility and effectiveness of PEC measurement under different circumstances. The PEC signal peak shows a linear relationship with the accumulated height and thereby is used as the signal feature for the quantitative measurement of accumulated height. A flexible sensor consisting of a replaceable flat cable with connectors at the ends is designed, following by the analyses of sensor offset and liftoff effects. To distinguish the unevenness of accumulation, the sensor-coil array scheme is proposed and the output array signals successfully characterize the profile of inner accumulation. Finally, a referencing strategy is explained to eliminate the interference due to magnetism transformation of the tube wall.

Numerical simulation and life prediction on T22 boiler tubes with steam-side and fire-side oxide scale

In this study based on Larsen-Miller empirical formula, two simulation models of T22 boiler tube of a super-heater are analyzed by Finite Element Method (FEM). Model one only considers the steam-side oxide scale, and model two considers both the steam-side and the fire-side oxide scale. The results show that the average temperature and Von Mises stresses of the tube increase gradually due to the existence of the steam-side and fire-side oxide scale, in which the effect of fire-side oxide scale is more remarkable. Based on the simulation results, Kachanov-Rabotnov creep damage model was employed to assess the creep life of the tube. It was found out that at the initial stage of the service time the fire-side oxide scale can protect the tube and delay the creep damage obviously, and the critical creep damage of the tube is only about 0.5 before failure occurs.

Vpliv škaje na parni strani cevi izmenjevalnika toplote na dobo trajanja cevi zaradi lezenja

Vpliv škaje na parni strani cevi izmenjevalnika toplote na dobo trajanja cevi zaradi lezenja

Influence of temperature on the oxide spallation of T91 alloy superheater tubes in power plant

The spallation of steam-side oxide scale on boiler tubes can seriously influence the safety of power plants. In this work, the failure behavior of oxide scale formed on T91 alloy superheater tubes was investigated using a uniaxial tension test at room temperature and at elevated temperature (300°C). Acoustic emission (AE) equipment was employed to monitor the failure evolution of oxide scale. The AE features associated with the metallographic investigation were adopted to detect the onset of each oxide failure type. The experimental results showed that oxide spallation occurred only at room temperature. For the elevated temperature test, no oxide spallation was found even at the maximum strain of 2%. An elastic-plastic finite element model was developed to understand the influence of temperature on the oxide failure. Results of the simulation revealed that the material property was one of key factors influencing the oxide spallation. Since the substrate yield strength decreased with increasing temperature, oxide spallation could be prevented at elevated temperature in the field.

Thermal Stress Development in Steam-Side Oxide Scales in High Temperature Components of Boilers under Thermal Shock

Failure of steam-side oxide scales in high temperature components of boilers such as superheater and reheater tubes has significant effect on the safety of thermal power plants. Finite element analysis is carried out to investigate the failure issues of steam-side oxide scales in boiler tubes during thermal shock processes. The effects of different steam temperature variation durations on oxide scale failure issues have been analyzed. According to the results, appropriately lengthening variation duration can contribute to relieving oxide scale failure issues, and are subsequently proposed.

Acoustic emission analysis on tensile failure of steam-side oxide scales formed on T22 alloy superheater tubes

Failure of steam-side oxide scales on boiler tubes can seriously influence the safety of coal-fired power plants. Uniaxial tensile tests employing acoustic emission (AE) monitoring were performed, in this work, to investigate the failure behavior of steam-side oxide scales on T22 alloy boiler superheater tubes. The characteristic frequency spectra of the captured AE signals were obtained by performing fast Fourier transform. Three distinct peak frequency bands, 100-170, 175-250, and 280-390 kHz, encountered in different testing stages were identified in the frequency spectra, which were confirmed to, respectively, correspond to substrate plastic deformation, oxide vertical cracking, and oxide spalling with the aid of scanning electronic microscopy observations, and can thus be used for distinguishing different oxide failure mechanisms. Finally, the critical cracking strain of the oxide scale and the interfacial shear strength of the oxide/substrate interface were estimated, which are the critical parameters urgently desired for modeling the failure behavior of steam-side oxide scales on boiler tubes of coal-fired power plants.

Oxide scale growth and presumed exfoliation in a 700 °C or higher steam condition: A simulation study for future operations of ultra-supercritical power plants

The world is facing the challenge of providing abundant and affordable electricity to meet the need of a growing global population, while lowering and controlling CO2 emissions. Both of these goals can be met through improving the efficiency of the boiler through increasing the operating pressure and temperature, although increasing steam temperature has been reported to be more economical than raising steam pressure. However, higher temperatures may lead to increased boiler tube failure through steam-side oxidation and fireside corrosion mechanisms. Ni-based alloys are candidate materials for these aggressive conditions. The study reported here is evaluating steam-side oxide growth in a given length of superheater and reheater tubes of ultra-supercritical boilers operating at 700°C or higher/35MPa steam condition under different presumed service conditions. A simple and inexpensive procedure to estimate the oxide scale growth and the metal temperature increase in a boiler tube over a period of time is proposed. Verification of the findings with the actual data from the power plants is provided. The oxide scale growth rates of nickel-based alloys at steam temperatures up to 750°C seemed to be tolerable in service based on the procedures demonstrated here.

Simulating the implications of oxide scale formations in austenitic steels of ultra-supercritical fossil power plants

Formation of steam-side oxide scale that can cause major failures in boilers is a large concern in fossil-fueled power plant operation. In this work, we attempt to simulate the implications of oxide scale formation and subsequently assumed exfoliation in the given length of an austenitic tube of ultra-supercritical (USC) fossil power plants under different presumed service conditions. The incremental procedures used to determine the average metal temperature and scale thickness over a period of time in superheater/reheater tubes at a specified steam temperature are presented. A number of simulation results for both formation and subsequent exfoliation of the oxide scales are presented and discussed. Based on the simulation results, the estimated scale growth and presumed exfoliation rate in austenitic steels at 650°C seemed to be allowable. However, to run USC power plants with steam condition of around 650°C, more detailed studies are required.

Estimation of residual life of boiler tubes using steamside oxide scale thickness

In thermal power plants, remaining-life-estimation of boiler tubes is required at regular intervals for a safer and a better functionality of boilers. In this paper, a new method is proposed for the residual life estimation of service exposed boiler tubes using Non-Destructive Ultrasonic Oxide scale thickness measurements, average metal temperature and creep master curve. While steady state conduction heat transfer equations are solved to calculate the average metal temperature, creep master curve is generated from short term stress rupture data of rupture life less than 5000 h on a virgin material. In the present study, the residual life of T22 (2.25Cr-1Mo) service exposed Platen Superheater tube is estimated using two master creep curves, i.e. Larson-Miller Parametric (LMP) method of standard ASME T22 creep data and Wilshire approach of short term stress rupture data of T22. As the residual life is calculated from fundamental conduction heat transfer theory and creep rupture data, the proposed method can be applied for different grades of boiler materials.

On the failure of steam-side oxide scales in high temperature components of boilers during unsteady thermal processes

Failure of steam-side oxide scales in high temperature components of boilers such as superheater and reheater tubes has significant effect on the safety of thermal power plants. Taking into account the influence that temperature has on physical properties of metal substrate and oxide scale, transient heat transfer model as well as multi-layered hollow cylinder stress model is successively developed in this work. Employing the Advanced Oxide Scale Failure Diagram (AOSFD) as failure criterion, a systematic analysis model for the failure behavior of steam-side oxide scales in T92 superheater tubes during unsteady thermal processes is established. Focusing on different steam temperature variation processes, the effects of steam-side oxide scale thickness as well as different steam temperature variation modes and variation durations on oxide scale failure issues have been analyzed. Besides, critical steam temperature drops leading to failure of oxide scales when steam temperature decreases linearly have also been investigated. Based on the analysis results, feasible measures such as selecting reasonable steam temperature variation mode and appropriately lengthening variation duration are subsequently proposed. The analysis results as well as the suggested measures in this work can provide valuable guidance for the solution of steam-side oxide scale failure issues in thermal power plants.

Microscopical investigation of steamside oxide on X20CrMoV121 superheater tubes

X20CrMoV121 is a 12%Cr martensitic steel which has been used in power plants in Europe for many decades. Superheater tubes exposed for various durations up to 135,000 h in power plants in Denmark at steam temperatures varying from 450 to 575°C were investigated. Light optical and scanning electron microscopy was used to investigate steamside oxide morphologies. At all temperatures there is a double layered oxide, however, the inner:outer oxide thickness is not always equal. At the lower steam temperature range of <500°C, there is an internal oxidation zone at the oxidation front indicating that chromium is less mobile at these temperatures. At a higher steam temperature range of 540 – 575°C the inner oxide consists of chromium rich and chromium poor oxide running parallel to the oxidation front indicating that the chromium is more mobile within the steel. Both types of morphology have been observed in the laboratory, however, the internal oxidation is observed up to 600°C and the chromium rich oxide striation are observed at 700°C.

Microscopical investigation of steamside oxide on X20CrMoV121 superheater tubes

Microscopical investigation of steamside oxide on X20CrMoV121 superheater tubes

Microscopical investigation of steamside oxide on X20CrMoV121 superheater tubes

X20CrMoV121 is a 12%Cr martensitic steel which has been used in power plants in Europe for many decades. Superheater tubes exposed for various durations up to 135,000 hours in power plants in Denmark at steam temperatures varying from 450 to 575°C were investigated. Light optical and scanning electron microscopy was used to investigate steamside oxide morphologies. At all temperatures there is a double layered oxide, however, the inner:outer oxide thickness is not always equal. At the lower steam temperature range of <500°C, there is an internal oxidation zone at the oxidation front indicating that chromium is less mobile at these temperatures. At a higher steam temperature range of 540 – 575°C the inner oxide consists of chromium rich and chromium poor oxide running parallel to the oxidation front indicating that the chromium is more mobile within the steel. Both types of morphology have been observed in the laboratory, however the internal oxidation is observed up to 600°C and the chromium rich oxide striation are observed at 700°C.

Microscopical investigation of steamside oxide on X20CrMoV121 superheater tubes

Microscopical investigation of steamside oxide on X20CrMoV121 superheater tubes

Influence of Oxide Growth and Metal Creep on Strain Development in the Steam-Side Oxide in Boiler Tubes

This effort is concerned with developing a quantitative description of the exfoliation behavior of oxide scales grown inside steam tubes in a pressure boiler. Consideration of the development of stress/strain in growing oxides has included expansion mismatch-induced strains during thermal cycling as well as inelastic mechanical effects from oxide/alloy creep phenomena and volume change from oxide growth. The magnitude of the parameters used has been closely matched to actual boiler operating practice. The creep model used was validated against published data. Representation of oxide growth-induced strain was found to be a difficult challenge because the processes involved are not fully understood. In addition to the traditional uniaxial (radial) and dilatational models, ‘lateral’ growth models are discussed in the context of experimentally-derived criteria, such as the level of elastic strains involved in oxide exfoliation. It was found that strain variation in the oxide cannot be neglected.

Fireside corrosion and steamside oxidation of 9–12%Cr martensitic steels exposed for long term testing

To obtain long term corrosion and steam oxidation data for the 9–12%Cr ferritic steels, test tube sections have been exposed in Amager 3 and Avedøre 1 coal fired power plants in Denmark (formerly run by ENERGI E2). Thus direct comparisons can be made for T91 and T92 for the 9%Cr steels and X20CrMoV121 and HCM12 for the 12%Cr steels. The test tubes were welded in as part of the existing final superheaters in actual plants and exposure has been conducted over a ten year period (1994–2005). Compared to the older steel types, T92 and HCM12 utilise tungsten to improve their creep strength. From Avedøre I testing, T91 and T92 can be compared for exposure times up to ∼48 000 h exposure. From Amager 3 testing, X20, HCM12 and T92 were tested; T92 has been exposed for up to 31 000 h and X20 and HCM12 have had 84 500 h exposure. Tube sections were removed for various exposure durations such that steamside oxidation and fireside corrosion could be investigated with respect to exposure time. The fireside corrosion rate was assessed by oxide thickness and in some cases residual metal thickness. The growth of steamside oxide was assessed by inner oxide thickness. The microstructure and chromium content of the corroded layers has been investigated using light optical and scanning electron microscopy. The fireside corrosion rate for the T92 and HCM12 steels are comparable to those of T91, however X20CrMoV121 has a higher fireside corrosion rate after the longest exposure time. For steamside oxidation, it was HCM12 that revealed high oxidation rates after the longest exposure time.

Steam Oxidation of TP 347H FG in Power Plants

The long term oxidation behaviour of TP 347H FG at ultra supercritical steam conditions was assessed by exposing the steel in test superheater loops in a Danish coal-fired power plant. The steamside oxide layer was investigated with scanning electron microscopy and energy dispersive X-ray diffraction in order to reveal the effect of oxidation time and temperature on the microstructure. A double layered oxide formed during steam oxidation. The morphology of the inner Cr-containing layer was influenced by the oxidation temperature. At temperatures below approx. 585oC, it consisted of regions of Fe-Ni-Cr spinel surrounded by Fe-Cr oxide. At higher temperatures almost the entire inner oxide layer was composed of Fe-Cr oxide. Possible mechanisms for the oxide growth are discussed and it is suggested that faster Cr transport within the alloy at higher temperatures explains the change in morphology. This hypothesis is supported by thermodynamic calculations and kinetic data. The thickness of the inner oxide layer did not change significantly with oxidation time and temperature for exposures less than 30000 h; however after 57554 h the thickness had increased significantly at the lowest temperatures.

Long term steam oxidation of TP 347H FG in power plants

AbstractThe long term oxidation behaviour of TP 347H FG at ultra supercritical steam conditions was assessed by exposing the steel in test superheater loops in a Danish coal-fired power plant. The steamside oxide layer was investigated with scanning electron microscopy and energy dispersive X-ray diffraction in order to reveal the effect of oxidation time and temperature on the microstructure.A double layered oxide formed during steam oxidation. The morphology of the inner Cr-containing layer was influenced by the oxidation temperature. At temperatures below 585°C, it consisted of regions of Fe–Ni–Cr spinel surrounded by Fe–Cr oxide. At higher temperatures almost the entire inner oxide layer was composed of Fe–Cr oxide. Possible mechanisms for the oxide growth are discussed and it is suggested that faster Cr transport within the alloy at higher temperatures explains the change in morphology.The thickness of the inner oxide layer appeared to be independent of oxidation time and temperature for exposes less...

Long term steam oxidation of TP 347H FG in power plants

The long term oxidation behaviour of TP 347H FG at ultra supercritical steam conditions was assessed by exposing the steel in test superheater loops in a Danish coal-fired power plant. The steamside oxide layer was investigated with scanning electron microscopy and energy dispersive X-ray diffraction in order to reveal the effect of oxidation time and temperature on the microstructure.A double layered oxide formed during steam oxidation. The morphology of the inner Cr-containing layer was influenced by the oxidation temperature. At temperatures below 585°C, it consisted of regions of Fe–Ni–Cr spinel surrounded by Fe–Cr oxide. At higher temperatures almost the entire inner oxide layer was composed of Fe–Cr oxide. Possible mechanisms for the oxide growth are discussed and it is suggested that faster Cr transport within the alloy at higher temperatures explains the change in morphology.The thickness of the inner oxide layer appeared to be independent of oxidation time and temperature for exposes less than 30 000 h; however, after 57 554 h, the thickness had increased significantly at the lowest temperatures.