Search Results for corrosion damage

Key components within gas turbines, such as the blades, can be susceptible to a range of degradation mechanisms, including hot corrosion. Hot corrosion type mechanisms describe a sequence of events that include the growth and fluxing of protective oxide scales followed by the degradation of the underlying coating/alloy; this can significantly reduce component lifetimes. To better understand the progress of this type of damage mechanism, a model of hot corrosion progression with both time and corrosive deposit flux is presented for IN738LC and compared to experimental test data collected at 700 °C for four different deposit fluxes. One approach to the interpolation of model parameters between these four fluxes is illustrated. Of particular importance is that the model accounts for the statistical variation in metal loss though the use of Weibull statistics.

Current nondestructive examination (NDE) technology detection capabilities limit our ability to detect stress corrosion cracking (SCC) damage until it has progressed significantly. This work describes the continued development of an in-situ monitoring technique to detect and characterize mechanical damage caused by SCC, allowing the detection of the incipient stages of damage to components/piping. The application of this study is to prevent failures in the primary cooling loop piping in nuclear plants. The main benefit to the industry will be improved safety and component lifetime assessment with fewer inspections. The technique utilizes high resolution fiber optic strain gages mounted on the pipe outside diameter (OD). This technique has successfully detected changes in the residual stress profile caused by a crack propagating from the pipe inside diameter (ID). The gages have a resolution of < 1 με. It has been shown experimentally for different crack geometries that the gages can readily detect the changes of approximately 10-60 με caused on the OD of the pipe due to crack initiation on the ID. This paper focuses on the latest in the development of the technology. Details of the previous work in this effort may be found in References 1 through 3. A short summary is provided in this paper. The main recent development was the full scale accelerated SCC cracking in boiling magnesium chloride (MgCl 2 ) experiment. In conjunction with experimentation, both 2D and 3D finite element (FEA) models with thermal and mechanical analyses have been developed to simulate the changes in residual stresses in a welded pipe section as a SCC crack progresses.

The combustion of coal and biomass fuels in power plants generates deposits on the surfaces of superheater / reheater tubes that can lead to fireside corrosion. This type of materials degradation can limit the lives of such tubes in the long term, and better methods are needed to produce predictive models for such damage. This paper reports on four different approaches that are being investigated to tackle the challenge of modelling fireside corrosion damage on superheaters / reheaters: (a) CFD models to predict deposition onto tube surfaces; (b) generation of a database of available fireside corrosion data; (c) development of mechanistic and statistically based models of fireside corrosion from laboratory exposures and dimensional metrology; (d) statistical analysis of plant derived fireside corrosion datasets using multi-variable statistical techniques, such as Partial Least Squares Regression (PLSR). An improved understanding of the factors that influence fireside corrosion is resulting from the use of a combination of these different approaches to develop a suite of models for fireside corrosion damage.

Modern gas turbines are operated with fuels that are very clean and within the allowances permitted by fuel specifications. However, the fuels that are being considered contain vanadium, sulfur, sodium and calcium species that could significantly contribute to the degradation of components in hot gas flow path. The main potential risk of material degradation from these fuels is “hot corrosion” due to the contaminants listed above combined with alkali metal salts from ambient air. Depending on the temperature regime hot corrosion can damage both TBC coatings and bond coat/substrate materials. Deposit-induced or hot corrosion has been defined as “accelerated oxidation of materials at elevated temperatures induced by a thin film of fused salt deposit”. For the initiation of hot corrosion, deposition of the corrosive species, e.g. vanadates or sulfates, is necessary. In addition to the thermodynamic stability, the condensation of the corrosive species on the blade/vane material is necessary to first initiate and then propagate hot corrosion. Operating temperatures and pressures both influence the hot corrosion damage. The temperature ranges over which the hot corrosion occurs depend strongly on following three factors: deposit chemistry, gas constituents and metal alloy (or bond coating/thermal barrier coating) composition. This paper reports the activities involved in establishing modeling and simulation followed by testing/characterization methodologies in relevant environments to understand the degradation mechanisms essential to assess the localized risk for fuel flexible operation. An assessment of component operating conditions and gas compositions throughout the hot gas paths of the gas turbines, along with statistical materials performance evaluations of metal losses for particular materials and exposure conditions, are being combined to develop and validate life prediction methods to assess component integrity and deposition/oxidation/corrosion kinetics.

The steam generation systems (SGS) of concentrated solar power (CSP) plants employ multiple heat exchangers arranged in series to convert thermal energy collected from the sun via a heat transfer fluid (HTF) to produce superheated steam in the Rankine cycle. Common CSP plant designs are based either on parabolic trough or central tower technology. The major Rankine cycle components consist of preheaters, evaporators, steam drums, superheaters, steam turbines, and water/air-cooled condensers, all connected through steel piping. For CSP plants capable of reheating the steam for improved efficiency, reheaters are also included in the Rankine cycle. In central tower design with directly heated water as the HTF, the receiver can also be considered part of the Rankine cycle. Operating experiences of CSP plants indicate that plant reliability is significantly impacted by failures in various components of the Rankine cycle. Many damage mechanisms have been identified, which include corrosion, thermal fatigue, creep, and stress corrosion cracking, among others. Much of the damage can be attributed to poor water/steam chemistry and inadequate temperature control. While damage in the Rankine cycle components is common, there is generally lack of comprehensive guidelines created specifically for the operation of these CSP components. Therefore, to improve CSP plant reliability and profitability, it is necessary to better understand the various damage mechanisms experienced by linking them to specific operating conditions, followed by developing a “theory and practice” guideline document for the CSP operators, so that failures in the Rankine cycle components can be minimized. In a major research project sponsored by the U.S. Department of Energy (DOE), effort is being undertaken by EPRI to develop such a guideline document exclusively for the CSP industry. This paper provides an overview of the ongoing DOE project along with a few examples of component failures experienced in the Rankine cycle.

Recently, single-phase flow accelerated corrosion (FAC) has been found extensively in Thailand, especially in single shaft combined cycle power plant heat recovery steam generators, the design of which are compact and cannot be easily accessed for service. This takes at least one week for repairing and costs at least half a million dollar per shutdown. In this paper, the investigation of the single-phase FAC in a high-pressure economizer of a combined cycle power plant is demonstrated. Water chemical parameters such as pH and dissolved oxygen are reviewed, the process simulation of the power plant is performed to capture risk areas for the FAC. A computational fluid dynamics study of the flow is done to understand the flow behavior in the damaged tubes next to an inlet header. Some modifications such as flow distributor installation and tube sleeve installation were performed for short-term solutions. Moreover, new economizer headers are designed with low alloy material to mitigate the problem. The installation process of the newly fabricated headers is finally described. The findings in this paper serve as a guideline for FAC risk assessment, FAC investigation and mitigation, and service in compact heat recovery steam generators.

In downstream oil industry applications, high-temperature sulfidation corrosion is generally caused by sulfur species coming from the crude; additionally, naphthenic acids or hydrogen can considerably worsen the corrosivity of the environment. During plant operations, several events may occur that boost the severity of corrosion: high feedstock turnover, with increasing “active” sulfur species; skin temperature rise due to the increasing insulation effect of the scale, generating an over-tempering of the material and possible degeneration into creep conditions. Thor115 is a ferritic steel with 11% chromium content to resist sulfidation. It has excellent creep properties for high temperature environments: higher allowable stresses than grade 91, keeping the same manufacturing and welding procedures. At the same time, it has the characteristics of ferritic steel, ensuring enhanced thermal conductivity and lower thermal expansion compared to austenitic steels. Comparative corrosion tests between Thor115 and other ferritic steels typically used in this industry (e.g., grade T/P5 and grade T/P9) have been carried out to simulate different corrosive conditions, confirming the superior properties of Thor115 relative to other ferritic grades. For these reasons, Thor 115 is a suitable replacement material for piping components that need an upgrade from grade T/P9 or lower, in order to reduce corrosion rate or frequency of maintenance operations.

The broken elbow of the final superheater tube (ASME SA213 TP304H) from a coal-fired power plant was evaluated. The root causes were identified by metallographic observation, sensitization evaluation, hardness measurement, and EBSD analysis. The analysis results reached the following conclusions. (1) The tube bending was not performed in accordance with ASME Code requirements—a solid-solution heat treatment was not performed after cold working. (2) The hardness at the elbow is greater than 260 HV, exceeding the ASME code limit. (3) The sensitization was 19%, showing a performance degradation. (4) There are no obvious corrosion elements in the oxide layers of the cracks. (5) Metallographic microstructure analysis shows that there are many intergranular cracks and carbides such as Cr-rich phase and Fe-Cr are precipitated at the grain boundaries, ultimately resulting in strain-induced precipitation hardening damage.

In Europe between 2006 and 2012 several ultra-super-critical (USC) coal-fired power plants were built employing T24 (7CrMoVTiB10-10 / DIN EN 10216-2:2014-03 / VdTÜV sheet 533/2) in membrane walls. During commissioning stress corrosion cracking (SCC) on the tube-to-tube butt welds appeared. The widespread damages required the development of a new patented commissioning procedure to avoid recurring damages. Although this commissioning procedure was employed successfully and the power plants are in operation since then, a debate about the implementation of a hardness limit for such butt welds was initiated. According to the European standards butt welds of T24 boiler tubes with wall thickness < 10 mm (0.3937 in) do not require any post-weld heat treatment (PWHT) and no hardness limits are given. When looking at manufacturing related issues such as an imminent risk of cold cracking after welding of micro-alloyed steels a widely applied but coarse hardness limit is 350 HV. Based on laboratory tests, some authors reallocated this 350 HV hardness limit for addressing SCC susceptibility of low-alloyed steels. This article describes typical hardness levels of T24 boiler tube TIG butt welds and the SCC behavior in high temperature water. Further the effect of the stress relief heat treatment (SRHT) of the boiler membrane walls between 450 °C and 550 °C (842 °F and 1022 °F) on its hardness values and on the SCC behavior is discussed, showing that the hardness values should not be used as an indicator for SCC susceptibility of T24 boiler tube butt welds.

There is a critical lack of data on the mechanical behavior of candidate structural materials for advanced nuclear reactors under molten halide salt environments. Limited legacy data from the molten salt reactor experiment (MSRE) program showed a significant reduction in creep rupture strength of a Ni-base alloy in molten fluoride salt. With ongoing efforts to commercialize different molten salt reactor concepts, the industry can considerably benefit from quantitative information on the impact of molten halide salts on the engineering properties such as creep and fatigue strength of materials of interest. The present work aims to assess the role of molten salt corrosion on the creep behavior of three alloys 316H, 617 and 282 at 650-816 °C. Creep tests were conducted in fluoride (FLiNaK) and chloride (NaCl-MgCl 2 ) salts. Initial results from the ongoing testing will be presented which suggest that the molten salt environment caused a 25-50% reduction in creep rupture lifetime compared to air exposures. Physics-based corrosion and creep models were employed to gain some insights into the potential degradation mechanisms.

Recently, boiler waterwall tube damage such as fireside corrosion and circumferential cracking in low NOx environments has become a serious issue in Japan, despite the typical use of relatively lower sulfur content coal is typically being used than in US. Thermal spray coating has been the most popular method for tube protection in Japan, and thermal spray coated tubes have been used for this purpose. However, extensive damage to thermal spray coating tubes from cracking and exfoliation has been recently experienced. It has been reported that the thermal fluctuations occurring due to operational changes create alternating stress, leading to cracking and exfoliation of the thermal sprayed thin coating. Corrosion-resistant weld overlays, such as Type 309 stainless steel (in sub-critical boilers) and Alloy 622 (in sub-critical and super-critical boilers), are commonly used to protect boiler tubes from corrosion in low NOx coal fired boilers in U.S. In order to develop a fundamental understanding of the high temperature corrosive behavior of Alloy 622 weld overlay, gaseous corrosion testing and certain mechanical tests for consideration of long-term aging were undertaken. After four years of service in the low NOx combustion environment of a coal fired supercritical boiler, field tests on Alloy 622 weld overlay panels are in continuation. This paper describes the field test behavior of Alloy 622 weld overlay panels installed in a Japanese supercritical boiler, the laboratory results of weight loss corrosion testing, and the results of cyclic bend tests with overlay welded tubes related to aging.

A failure of the upper casing of the circulation pump led to a big damage in the PP Staudinger unit 5 on 12th of May 2014. According to the §18(2) BetrSichV an extensive root cause analysis (RCA) was started. From the beginning on different lines of activities were initiated to handle the situation with the required diligence. Decisions were made, taking into account safety regulations, possibility of repair and best practice engineering. Following the board decision to repair the unit 5, a lot of detailed work was done. All of the performed work packages were linked in different timelines and needed to meet in the key points. Consequently it was a challenge to achieve the agreed date of unit 5 restart on 15th of January 2015. The unit restart on the targeted date was a proof of the excellent collaboration between all involved parties. The presentation gives a summarizing overview about the damage, the main results of the RCA and the repair activities.

This presentation compares the corrosion resistance of uncoated Haynes 230 and SS316HS substrates to the same substrates coated with a Fe-based amorphous alloy. The substrates were exposed to highly corrosive media, FLiNaK, for 120 hours at 700 °C. The findings indicate that the thermal spray amorphous alloy coating provided superior corrosion resistance within the coatings while protecting the substrates against the aggressive environment. As a result, the new amorphous metal coating improved the substrate's lifespan by providing better protection against high-temperature corrosion, paving the way for a more efficient and cost-effective future in various industrial applications.

For four decades, the Electric Power Research Institute (EPRI) has led groundbreaking materials research in the power industry, yielding significant cost savings across fossil, nuclear, and power delivery sectors. This paper outlines EPRI's fossil-related research, conducted through three major programs: Fossil Materials&Repair (P87 Base program), Materials-Fossil&Nuclear strategic program, and a supplemental program addressing key industry initiatives. EPRI's research focuses on understanding damage mechanisms, developing improved materials, enhancing life prediction methodologies, and advancing component degradation assessment. The paper highlights the synergy between EPRI's short- and long-term research initiatives, referencing several presentations from the 6th International Conference on Advances in Materials Technology for Fossil Power Plants. By showcasing EPRI's comprehensive approach to materials research, this overview demonstrates the institute's ongoing commitment to advancing power generation technology and efficiency.

Research has demonstrated that creep damage in power plant steels is directly linked to grain boundary precipitates, which serve as nucleation sites for cavities and micro-cracks. The formation of M 23 C 6 carbides along grain boundaries creates chromium-depleted zones vulnerable to corrosion and significantly reduces creep life due to rapid coarsening. Through combined Monte Carlo grain boundary precipitation kinetics and continuum creep damage modeling, researchers have predicted that increasing the proportion of MX-type particles could enhance creep performance. This hypothesis was tested using hafnium-containing steel, which showed improved creep and corrosion properties in 9% Cr steels. Ion implantation of Hafnium into thin foils of 9 wt% Cr ferritic steel resulted in two new types of precipitates: hafnium carbide (MX-type) and a Cr-V rich nitride (M 2 N). The hafnium carbide particles, identified through convergent beam diffraction and microanalysis, appeared in significantly higher volume fractions compared to VN in conventional ferritic steels. Additionally, Hafnium was found to eliminate M 23 C 6 grain boundary precipitates, resulting in increased matrix chromium concentration, reduced grain boundary chromium depletion, and enhanced resistance to intergranular corrosion cracking.

A research program has been initiated to develop the first predictive methodology for corrosion fatigue life in steam turbine blades, addressing a critical gap in current understanding despite extensive research into corrosion pitting and fatigue failure. The study focuses initially on dual-certified 403/410 12% Cr stainless steel, utilizing a newly developed test facility capable of conducting high-cycle fatigue tests in simulated steam environments at 90°C with controlled corrosive conditions. This testing platform enables the investigation of various steady and cyclic stress conditions, establishing a foundation for future testing of other blade steels and the development of comprehensive blade life estimation techniques.

Starting in 2010 a new generation of coal fired power plants in Europe operating at a steam temperature of up 620°C was commissioned. During that commissioning process many cracks occurred in welds of T24 material which was extensively used as membrane wall material in nearly all of the new boilers. The cracks were caused by stress corrosion cracking (SCC) only occurring in the areas of the wall being in contact to high temperature water during operation. The question which step of the commissioning process really caused the cracking was not answered completely even several years after the damage occurred. To answer this question and to define parameters which will lead to cracking in high temperature water many tests were conducted. Generally it was found that slow tensile tests in controlled environment are well suited to get information about materials SCC sensitivity in the laboratory. In the present paper, first the influence of the cracking of welded T24 material in acidic environment containing well-defined amounts of H2S is investigated to address the question if a chemical cleaning process prior to the testing might lead to hydrogen induced SCC. As a second step, cracking behaviour in high temperature water is being investigated. Here the influence of the temperature, the oxygen concentration of the water, the deformation speed of the sample, the heat treatment and the condition of the material on the SCC is analysed.

This paper addresses thermal shock cracking, a critical damage mechanism for pressurized components, currently absent from design and fitness-for-purpose codes. It analyzes the crack growth mechanisms and proposes guidelines for designing vessels to resist thermal shock crack initiation and for assessing the significance of existing cracks discovered during service. Thermal shock crack growth is influenced by factors like shock severity, applied mechanical stress, and the corrosive environment. In service, cracks often arrest and pose minimal risk. This work explores a broader range of conditions, offering a less conservative approach compared to existing EPRI guidelines.

High efficiency in power generation is not only desirable because of economical reasons but also for enhanced environmental performance meaning reduced quantity of forming ash and emissions. In modern medium to large size plants, improvements require supercritical steam values. Furthermore, in future there will be an increasing share of renewables, such as wind and solar power, which will enhance the fluctuation of supply with the consequence that other power sources will have to compensate by operating in a more demanding cyclic or ramping mode. The next generation plant will need to operate at higher temperatures and pressure cycles coupled with demanding hot corrosion and oxidation environments. Such an operation will significantly influence the performance of materials used for boilers and heat exchanger components by accelerating oxidation rates and lowering mechanical properties like creep resistance. The paper discusses the oxidation behaviour of San25, 800H and alloy 263 in supercritical water at temperatures 650 and 700 °C at 250 bar, and compares the changes of mechanical properties of materials at these temperatures.

The increasing steam parameters in modern high-efficiency fossil fuel power plants demand advanced materials with enhanced creep strength for operation under extreme temperature and pressure conditions. Tenaris has focused on developing ferritic-martensitic and austenitic grades for tube and pipe applications. At TenarisDalmine, efforts on ferritic-martensitic steels include ASTM Grade 23, a low-alloyed alternative to Grade 22 with 1.5% W, offering good weldability, creep resistance up to 580°C, and cost competitiveness. Additionally, ASTM Grade 92, an improved version of Grade 91, provides high creep strength and long-term stability for components like superheaters and headers operating up to 620°C. At TenarisNKKT R&D, austenitic steel development includes TEMPALOY AA-1, an improved 18Cr-8NiNbTi alloy with 3% Cu for enhanced creep and corrosion resistance, and TEMPALOY A-3, a 20Cr-15Ni-Nb-N alloy with superior creep and corrosion properties due to its higher chromium content. This paper details the Tenaris product lineup, manufacturing processes, and key material properties, including the impact of shot blasting on the steam oxidation resistance of austenitic grades. It also covers ongoing R&D efforts in alloy design, creep testing, data assessment, microstructural analysis, and damage modeling, conducted in collaboration with Centro Sviluppo Materiali.