Search Results for corrosion monitoring

Structural alloy corrosion is a major concern for the design and operation of supercritical carbon dioxide (sCO 2 ) power cycles. Looking towards the future of sCO 2 system development, the ability to measure real-time alloy corrosion would be invaluable to informing operation and maintenance of these systems. Sandia has recently explored methods available for in-situ alloy corrosion monitoring. Electrical resistance (ER) was chosen for initial tests due the operational simplicity and commercial availability. A series of long duration (>1000 hours) experiments have recently been completed at a range of temperatures (400-700°C) using ER probes made from four important structural alloys (C1010 Carbon Steel, 410ss, 304L, 316L) being considered for sCO 2 systems. Results from these tests are presented, including correlations between the probe measured corrosion rate to that for witness coupons of the same alloys.

A consortium which includes Energy Industries of Ohio, the Electric Power Research Institute, Inc., and four major US boiler manufacturers (the Babcock & Wilcox Company, Riley Power, Foster Wheeler, and Alstom Power) is conducting a 5-year materials development program to advance the technology in coal-fired power generation. As part of this development effort, new high temperature, corrosion resistant alloys must be evaluated and qualified for dependable operation in a corrosive coal-fired environment to produce steam for Ultra Supercritical (USC) cycle operation up to 760°C (1400°F) and 35 MPa (5000 psi.) To evaluate the fireside corrosion resistance of candidate materials for USC power generation, two superheater test loops comprised of seven different advanced alloys were designed and fabricated by the Babcock and Wilcox Company (B&W) in Barberton, Ohio. These loops were installed at the Reliant Energy power plant located in Niles, OH, and testing of these loops was initiated in December, 2003. Following a minimum of 18 months of testing, the loops will be removed for metallurgical examination and assessment by B&W. This paper describes some of the considerations in designing, fabricating, and installing the two USC test loops, as well as the methodology for monitoring their performance during operation.

The spalling of oxide scales at the steam side of superheater and reheater of ultra-supercritical unit is increasingly serious, which threatens the safe and economic operation of the boiler. However, no effective monitoring method is proposed to provide an on-line real-time detection on the spalling of oxide scales. This paper proposes an on-line magnetic non-destructive testing method for oxide granules. The oxide scale-vapor sample from the main steam pipeline forms liquid-solid two-phase flow after the temperature and pressure reduction, and the oxide granules are separated by a separator and piled in the austenitic pipe. According to the difference of the magnetic features of the oxide scales and the austenitic pipe, the oxide granule accumulation height can be detected through the spatial gradient variations of the magnetic induction. The laboratory test results show that the oxide scale accumulation can be accurately calculated according to the spatial gradient changes around the magnetized oxide granules, with the detection error not exceeding 2%.

The incore instrumentation system of a pressurized water reactor (PWR) facilitates neutron flux mapping and temperature measurements at specific core locations. A guide conduit, extending from the seal table to the lower reactor pressure vessel head, guides and protects each incore guide thimble between the table and the lower reactor vessel head. Each flux thimble houses a detector and drive cable. Once filled with reactor coolant, the conduit becomes an extension of the reactor coolant pressure boundary. This paper reports the examination results of cracking detected in a TP304 stainless steel guide conduit adjacent to a fillet weld at the upper surface of a TP304 seal table. The cracking resulted in reactor coolant leakage that was detected by the presence of boric acid deposits on the exterior of the conduit and table. Failure analysis including dimensional measurements, chemical analysis, stereomicroscopy, metallography, and scanning electron microscopy showed that extensive cracking of the conduit and seal table material occurred due to stress corrosion cracking (SCC). Assessment showed that chlorine-containing deposits were present on the exterior of the conduit and on the surfaces of the seal table and were due to the design and operation of HVAC systems at the coastal plant. Stainless steels are susceptible to SCC in environments with elevated temperatures, chloride contents, and increased tensile stress – particularly in non-post weld heat treated (PWHT) weld regions and the heat affected zone (HAZ). This was the apparent primary cause of the failure. However, chloride-induced SCC of such materials typically results in transgranular crack propagation, whereas the observed cracks were indicative of intergranular stress corrosion cracking (IGSCC). Microstructural analysis showed that the observed cracks initiated in sensitized areas of material adjacent to the weld. Sensitization of the material caused chromium depletion from adjacent areas and increased susceptibility of the depleted areas to IGSCC. In this case, the most probable source of sensitization was related to welding and the long-term growth of grain boundary carbides nucleated during welding. This was considered a contributing cause to the failure.

Stress corrosion cracking (SCC) is a potential risk in structural steels used for steam boilers. To investigate the effect of dissolved oxygen (DO) on SCC susceptibility, three steels, T23, T24 and T91 were annealed at 1065°C and then quenched to create a susceptible microstructure and then exposed in a Jones test to stagnant and circulating water at 200°C with varying DO levels. The results indicated that among the tested steels, the SCC susceptibility was highest in T91 but lowest in T23 which did not exhibit crack initiation with 100 ppb DO. T24 showed no cracking with 50 ppb DO but cracked with 100 ppb DO under these conditions. Based on these results, the next planned step is to monitor crack growth in-situ and determine a critical DO content for each material.

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 Department of Energy and Ohio Coal Development Office jointly sponsored research to evaluate materials for advanced ultrasupercritical (A-USC) coal power plants, testing both monolithic tube materials and weld overlay combinations under real operating conditions. Testing was conducted in the highly corrosive, high-sulfur coal environment of Reliant Energy's Niles Plant Unit 1 boiler in Ohio. After 12 months of exposure, researchers evaluated six monolithic tube materials and twelve weld overlay/tube combinations for their high-temperature strength, creep resistance, and corrosion resistance in both steam-side and fire-side environments. Among the monolithic materials, Inconel 740 demonstrated superior corrosion resistance with the lowest wastage rate, while EN72 emerged as the most effective weld overlay material across various substrates, offering consistent protection against corrosion.

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.

The U.S. Department of Energy (DOE) and the Ohio Coal Development Office (OCDO) are co-sponsoring a multi-year project managed by Energy Industries of Ohio (EIO) to evaluate materials for ultra-supercritical (USC) coal-fired boilers. USC technology improves cycle efficiency and reduces CO 2 and pollutant emissions. With turbine throttle steam conditions reaching 732°C (1350°F) at 35 MPa (5000 psi), current boiler materials, which operate below 600°C (1112°F), lack the necessary high-temperature strength and corrosion resistance. This study focuses on the fireside corrosion resistance of candidate materials through field testing. Evaluated materials include ferritic steels (SAVE12, P92, HCM12A), austenitic stainless steels (Super304H, 347HFG, HR3C), and high-nickel alloys (Haynes 230, CCA617, Inconel 740, HR6W), along with protective coatings (weld overlays, diffusion coatings, laser claddings). Prior laboratory tests assessed corrosion under synthesized coal-ash and flue gas conditions for three North American coal types (Eastern bituminous, Midwestern high-sulfur bituminous, and Western sub-bituminous), with temperatures ranging from 455°C (850°F) to 870°C (1600°F). Promising materials were installed on retractable corrosion probes in three utility boilers burning different coal types. The probes maintained metal temperatures between 650°C (1200°F) and 870°C (1600°F). This paper presents new fireside corrosion probe results after approximately one year of exposure for Midwestern and Western coal types.

High-temperature solid particle erosion (SPE) is a major threat to efficiency in power plants and jet engines, potentially reducing turbine efficiency by 7-10% and causing significant CO 2 emissions. The sources of these particles vary widely, from volcanic ash in engines to fly ash in boilers and scale in turbines. While better surface engineering and coatings offer solutions, their development is hampered by a lack of standardized test methods and reliable models. To address this, the METROSION initiative aims to establish a comprehensive framework for characterizing the high-temperature SPE performance of new materials and coatings. This framework will require a step change in test methods and control, focusing on accurately measuring key parameters like temperature, flow rate, particle properties, and impact angles. This paper outlines the initiative’s goals, with a particular focus on the techniques used for in-situ measurements of temperature, particle velocity, and 3D shape/size.

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.

Super Duplex stainless steels (SDSS) are alloys based on the Fe-Cr-Ni-N system. The chemical composition is tailored to achieve a balanced microstructure of 50% ferrite and 50% austenite. Hyper Duplex Stainless Steels (HDSS) are also duplex materials distinguished by their remarkable yield strength (≥700 MPa) and corrosion resistance (PREN>48). They have been developed as an alternative to the well-established SDSS when superior mechanical and corrosion performance is required. This enhanced performance is attributed to alloying additions, primarily Cr, Mo, and N. In this study, a comparison is conducted between filler metals of SDSS and HDSS for the root welding of SDSS plates. The gas tungsten arc welding (GTAW) process was used to carry out root welding passes and Gas Metal Arc Welding (GMAW) for filling passes on SDSS substrates arranged in a V groove to simulate a repair scenario. The heat input was controlled in both processes, keeping it below 2.0 kJ/mm in the GTAW and 1.2 kJ/mm in the GMAW. GTAW with constant current was used and the parameters achieved producing full penetration welds with SDSS and HDSS. In this case, Nitrogen was used as backing gas to avoid oxidation of the root. Thus, a special GMAW-Pulsed version was applied to achieve good wettability and defect-free joints. ASTM G48 tests were performed to evaluate the corrosion resistance through Critical Pitting Testing (CPT) analysis on the root pass, microstructural analysis via optical microscopy, and impact toughness. Consequently, a comprehensive examination of the welded joints outlines manufacturing conditions, limitations, and the applications of SDSS and HDSS filler metals.

Laboratory-scale tests are frequently used to generate understanding of high-temperature oxidation phenomena, to characterise and rank the performance of existing, future materials and coatings. Tests within the laboratory have the advantage of being well controlled, monitored and offer the opportunity of simplification which enables the study of individual parameters through isolating them from other factors, such as temperature transients. The influence of pressure on the oxidation of power plant materials has always been considered to be less significant than the effects of temperature and Cr content, but still remains a subject of differing opinions. Experimental efforts, reported in the literature, to measure the influence of steam pressure on the rate of oxidation have not produced very consistent or conclusive results. To examine this further a series of high pressure steam oxidation exposures have been conducted in a high pressure flowing steam loop, exposing a range of materials to flowing steam at 650 and 700 °C and pressure of 25, 50 and 60 bar. Data is presented for ferritic-martensitic alloys showing the effect of increasing pressure on the mass change and oxide thickness of these alloys in the flowing steam loop. In addition the effect observed on the diffusion of aluminium from an aluminised coating in these alloys is also presented and the differences in the extent of diffusion discussed.

This paper introduces the GKM (Grosskraftwerk Mannheim AG) test rig, designed to evaluate new Ni-based alloys and austenitic steels for components in advanced 700°C power plants under real operational conditions. The test rig, integrated into a conventional coal-fired power plant in Mannheim, Germany, simulates extreme conditions of up to 725°C and 350/200 bar pressure. After approximately 2000 hours of operation, the paper presents an overview of the rig's design, its integration into the existing plant, and the status of ongoing tests. It also outlines parallel material investigations, including creep rupture tests, mechanical-technological testing, and metallurgical characterization. This research is crucial for the development of materials capable of withstanding the severe conditions in next-generation power plants, potentially improving efficiency and performance in future energy production.

The drive for increased efficiency and carbon reduction in next-generation boilers is pushing conventional materials to their limits in terms of strength and oxidation resistance. While traditional isothermal testing of simple coupons provides some insight into material performance, it fails to accurately represent the heat transfer conditions present in operational boilers. This paper introduces a novel test method designed to evaluate the degradation of candidate materials under more realistic heat flux conditions. The method, applied to tubular specimens using both laboratory air and steam as cooling media, demonstrates a significant impact of thermal gradients on material performance. Initial comparisons between tubular heat flux specimens and flat isothermal specimens of 15Mo3 revealed increased oxidation kinetics and altered oxide morphology under heat flux conditions. The paper details the design of this heat flux test, presents results from initial work on 15Mo3 under air and steam conditions, and includes findings from further studies on oxides formed on 2-1/4Cr material under both heat flux and isothermal conditions. This research represents a crucial step toward more accurate prediction of material behavior in next-generation boiler designs.

The mechanisms of recent cracking failures of HR3C super heater pipes of a fossil power plant in the Netherlands were investigated. Initial failure investigations showed that pitting corrosion of the sensitized HR3C initiated subsequent stress corrosion cracking (SCC). It was concluded that magnesium chloride hydrates from condensed seawater had initiated pitting corrosion as well as SCC similar to the standard ASTM G36 SCC test. By experimental application of the ASTM G36 procedure, this tentative mechanism is reproduced and confirmed by a series of laboratory tests with pure magnesium chloride as well as with synthetic seawater. It included the effects of temperature, magnesium chloride concentrations of the evaporating water and applied bending moments on cracking. As a result for the 175h testing period in MgCl2*6H 2 O cracking increases significantly above 100°C up to 120°C but is reduced slightly at temperatures up to 155°C. With increasing bending moments, the U-shaped test pieces revealed increasing crack depths up to total fracture of the 5mm thick sections. Lower magnesium chloride concentrations as in concentrated seawater provided identical cracking, however, to a lower extent. It is therefore concluded that the operational failure of the sensitized HR3C super heater pipes was initiated in presence of condensed seawater and followed the same mechanism as found in the experimental investigation. As a conclusion, the presence of seawater saturated air at temperatures between 100° and 155°C should be avoided.

The EU NextGenPower-project aims at demonstrating Ni-alloys and coatings for application in high-efficiency power plants. Fireside corrosion lab and plants trials show that A263 and A617 perform similar while A740H outperforms them. Lab tests showed promising results for NiCr, Diamalloy3006 and SHS9172 coatings. Probe trials in six plants are ongoing. A617, A740H and A263 performed equally in steamside oxidation lab test ≤750°C while A617 and A740H outperformed A263 at 800°C; high pressure tests are planned. Slow strain rate testing confirmed relaxation cracking of A263. A creep-fatigue interaction test program for A263 includes LCF tests. Negative creep of A263 is researched with gleeble tests. A263 Ø80 - 500mm trial rotors are forged with optimized composition. Studies for designing and optimizing the forging process were done. Segregation free Ø300 and 1,000mm rotors have been forged. A263 – A263 and A293 – COST F rotor welding show promising results (A263 in precipitation hardened condition). Cast step blocks of A282, A263 and A740H showed volumetric cracking after heat treatment. New ‘as cast’ blocks of optimized composition are without cracks. A 750°C steam cycle has been designed with integrated CO 2 capture at 45% efficiency (LHV). Superheater life at ≤750°C and co-firing is modeled.

In both direct- and indirect-fired supercritical CO 2 (sCO 2 ) cycles, there is considerable interest in increasing the size and efficiency of such systems, perhaps by increasing the peak temperature to >700°C. However, relatively little experimental data are available under these conditions with pressures of 200-300 bar. Furthermore, impurities such as O 2 and H 2 O in the CO 2 may greatly alter the compatibility of structural alloys in these environments. While an experimental rig is being constructed that can measure and control the impurity levels in sCO 2 at 200-300 bar, initial 1 bar experiments at 700°-800°C for 500 h have been conducted in high-purity and industrial grade CO 2 , CO 2 +0.15O 2 and CO 2 +10%H 2 O and compared to exposures in dry air and 200 bar sCO 2 . These results, focusing on Fe- and Ni-base structural alloys and commercial chromia- and alumina-forming alloys, indicate that modifications in the environment did not strongly affect the reaction products at 700°-800°C.

In today’s market place power generation plants throughout the world have been trying to reduce their operating costs by extending the service life of their critical machines such as steam turbines and gas turbines beyond the design life criteria. The key ingredient in plant life extension is remaining life assessment technology. This paper will outline remaining life procedures which will incorporate the defect tolerant design concepts applied to the various damage mechanisms such as creep, fatigue, creep-fatigue and stress corrosion cracking. Also other embrittlement mechanisms will also be discussed and how they will influence the life or operation of the component. Application of weld repairs to critical components such as rotors and steam chest casings will be highlighted and how defect tolerant design concept is applied for the repair procedure and the acceptance standard of the nondestructive testing applied. Also highlighted will be various destructive tests such as stress relaxation tests (SRT) which measures creep strength and constant displacement rate test (CDRT) which evaluates fracture resistance or notch ductility. Also shown will be actual life extension examples applied to steam turbine components and weld repairs. Utilization of computer software to calculate fatigue and creep fatigue crack growth will also be presented

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.