Copper piping in a closed-loop water heater system was found to be corroded with MIC and erosion of the weak oxide layer. Investigation (visual inspection, bacterial corrosion cultures, and 20x/400x micrographs) supported the conclusion that the corrosion was caused by microbiological attack, specifically sulfur-reducing bacteria. No recommendations were made.

This article describes the methodology for performing a failure modes and effects analysis (FMEA). It explains the methodology with the help of a hot water heater and provides a discussion on the role of FMEA in the design process. The article presents the analysis procedures and shows how proper planning, along with functional, interface, and detailed fault analyses, makes FMEA a process that facilitates the design throughout the product development cycle. It also discusses the use of fault equivalence to reduce the amount of labor required by the analysis. The article shows how fault trees are used to unify the analysis of failure modes caused by design errors, manufacturing and maintenance processes, materials, and so on, and to assess the probability of failure mode occurrence. It concludes with information on some of the approaches to automating the FMEA.

Carbon steel tubes from a boiler feedwater heater feeding a deaerator were treated to control scale formation, but the treatment instead produced more iron oxide. The additional iron oxide reduced the tubing to a totally corroded condition. Investigation showed that the chelate injected to control the scaling was added ahead of the preheater, where the boiler water still contained oxygen. As the chelate removed iron oxide, the O2 in the water continued to form more. Recommendations included moving the chelate addition to a point after the deaerator to stop the corrosion.

The working fluid of a hypersonic wind tunnel is freon 14 heated in molten-metal-bath heat exchangers. The coils of the heaters have failed several times from various causes. They have been replaced each time with a stainless steel deemed more appropriate, but they continue to fail. In this case study, the history of failures is traced, the causes are analyzed, and recommendations are made for future design and maintenance. Coils fabricated from AISI 316 should provide satisfactory service life if reasonable precautionary measures are observed during maintenance and testing.

A closed-loop hot water heating system at a museum in South Carolina was the subject of failure evaluation. The system consisted of plain carbon steel pipes (Schedule 40) made of ASTM A 106 or A 53 (ERW or seamless). The supply and return lines were made of the same materials. The fittings were mechanically threaded assemblies. Temperatures ranged from 150 to 155 deg F (65.6 to 68.3 deg C). Leaks in the system had reportedly initiated immediately after the building had been placed in service. The cause of corrosion inside the steel pipes was attributed to tuberculation caused by oxygen concentration cells and oxygen-pitting related corrosion. Both types of corrosion are due to the poor quality of the water and the lack of corrosion control in the water system.

This article describes the characteristics of tubing of heat exchangers with respect to general corrosion, stress-corrosion cracking, selective leaching, and oxygen-cell attack, with examples. It illustrates the examination of failed parts of heat exchangers by using sample selection, visual examination, microscopic examination, chemical analysis, and mechanical tests. The article explains corrosion fatigue of tubing of heat exchangers caused by aggressive environment and cyclic stress. It also discusses the effects of design, welding practices, and elevated temperatures on the failures of heat exchangers.

The brine-heater shell in a seawater-conversion plant failed by bursting along a welded joint connecting the hot well (C70600 per ASTM B 466) to the heater shell (ASTM A285, grade C steel). Three cracks in the welded joints between the heater shell and the hot well were revealed by visual inspection. It was observed that crack 1 and 2 were covered with high-temperature oxidation products which revealed that the surfaces had been separated for quite some time. A very high discontinuity stress which existed at the longitudinal welds between the hot well and the heater shell was revealed by stress analysis. It was interpreted that the cracks had originated shortly after the heater was put into operation and propagated slowly initially. The rate of propagation was interpreted to have increased due to discontinuity stresses greater than yield strength of the material. It was concluded that the brine heater cracked and fractured because it was overstressed in normal operation. The heater design was modified to make the heater shell and the hot well two separate units. A relief valve was recommended in the heater or in the steam line near the heater.

Heat exchangers are devices used to transfer thermal energy between two or more fluids, between a solid surface and a fluid, or between a solid particulate and a fluid at different temperatures. This article first addresses the causes of failures in heat exchangers. It then provides a description of heat-transfer surface area, discussing the design of the tubular heat exchanger. Next, the article discusses the processes involved in the examination of failed parts. Finally, it describes the most important types of corrosion, including uniform, galvanic, pitting, stress, and erosion corrosion.

Persistent leakage was experienced from copper tube heaters which formed part of dairy equipment. Metallurgical examination of the brazed joints showed them to have suffered a preferential corrosion attack. This resulted in the phosphide phase of the brazing alloy being corroded away, leaving a weak, porous residual structure. The brazing alloy was of type CP 1 as covered by BS 1845. Header and tube materials were basically copper-nickel alloys for which the use of a phosphorus bearing brazing alloy is not recommended owing to the possibility of forming the brittle intermetallic compound, nickel phosphide. The use of a brazing alloy containing phosphorus was unsuitable on two counts and a quaternary alloy containing silver, copper, cadmium and zinc, such as those in group AG1 or AG2 of BS 1845 would be more suitable. However, because corrosive problems experienced in these units indicated severe service conditions, a proprietary alloy similar to AG1, but containing 3% nickel, was recommended.

A sleeve-shaped fire shield that operates inside one of two burner trains in an oil and gas processing unit ruptured after 15 y of service. A detailed analysis was conducted to determine how and why the sleeve failed. The investigation included visual inspection, chemical and gas analysis, mechanical property testing, stereomicroscopy, and metallographic examination. The fire sleeves are fabricated from 3-mm thick plate made of Incoloy 800 rolled into 540-mm diam sections welded along the seam. Three such sections are joined together by circumferential welds to form a single 2.8 m sleeve. The findings from the investigation indicated that internal oxidation corrosion, driven by high temperatures, was the primary cause of failure. Prolonged exposure to temperatures up to 760 °C resulted in sensitization of the material, making it vulnerable to grain boundary attack. This led to significant deterioration of the grain boundaries, causing extensive grain loss (grain dropping) and the subsequent thinning of sleeve walls. Prior to failure, some portions of the sleeve were only 1.6 mm thick, nearly half their original thickness.

The failure of T12 reheater tubes that had been in service for only 3000 h was investigated. The thickness of the tubes was visibly reduced by heavy oxidation corrosion on the inner and outer walls. The original pearlite substrate completely decomposed. Uniform oxide scale observed on the inner wall showed obvious vapor oxidation corrosion characteristics. Corrosion originated in the grain boundary, and selective oxidation occurred due to ion diffusion in the substrate. The layered oxide scale on the inner wall is related to the different diffusion rates for different cations. Exposure to high temperature corrosive flux accelerated the corrosion on the outer wall. Microstructure degradation and the corrosion characteristics observed indicate that the tubes failed primarily because of overheating, which is confirmed by calculations.

Failures in boilers and other equipment taking place in power plants that use steam as the working fluid are discussed in this article. The discussion is mainly concerned with failures in Rankine cycle systems that use fossil fuels as the primary heat source. The general procedure and techniques followed in failure investigation of boilers and related equipment are discussed. The article is framed with an objective to provide systematic information on various damage mechanisms leading to the failure of boiler tubes, headers, and drums, supplemented by representative case studies for a greater understanding of the respective damage mechanism.

The assignment of financial liability for turbine blade failures in steam turbines rests on the ability to determine the damage mechanism or mechanisms responsible for the failure. A discussion is presented outlining various items to look for in a post-turbine blade failure investigation. The discussion centers around the question of how to determine whether the failure was a fatigue induced failure, occurring in accordance with normal life cycle estimates, or whether outside influences could have initiated or hastened the failure.

A 5000-gal (20,000-L) hot-water holding tank fractured at a large automotive manufacturing plant. The tank was made from Type 304 austenitic stainless steel. The inner diameter of the tank displayed a macroscopic, web-like network of cracks that deceptively suggested intergranular stress-corrosion cracking. The problem, however, originated on the outside surface of the tank where a tensile stress (due to low applied stress and fabrication-induced residual stresses) accelerated the growth of numerous stress corrosion cracks that eventually broke through to the inner surface, causing leakage and ultimately failure.

Alloy 430 stainless steel tube-to-header welds failed in a heat recovery steam generator (HRSG) within one year of commissioning. The HRSG was in a combined cycle, gas-fired, combustion turbine electric power plant. Alloy 430, a 17% Cr ferritic stainless steel, was selected because of its resistance to chloride and sulfuric acid dewpoint corrosion under conditions potentially present in the HRSG low-pressure feedwater economizer. Intergranular corrosion and cracking were found in the weld metal and heat-affected zones. The hardness in these regions was up to 35 HRC, and the weld had received a postweld heat treatment (PWHT). Metallographic examination revealed that the corroded areas contained undertempered martensite. Fully tempered weld areas with a hardness of 93 HRB were not attacked. No evidence of corrosion fatigue was found. Uneven temperature control during PWHT was the most likely cause of failure.

This article explains the main types and characteristic causes of failures in boilers and other equipment in stationary and marine power plants that use steam as the working fluid with examples. It focuses on the distinctive features of each type that enable the failure analyst to determine the cause and suggest corrective action. The causes of failures include tube rupture, corrosion or scaling, fatigue, erosion, and stress-corrosion cracking. The article also describes the procedures for conducting a failure analysis.

A back wall riser tube in a high pressure boiler failed, interrupting operations in a cogeneration plant. The failure occurred in a tube facing the furnace, causing eight ruptured openings over a 1.8 m section. The investigation consisted of an on-site visual inspection, nondestructive testing, energy dispersive x-ray analysis, and inductively coupled plasma mass spectrometry. The tube was made from SA 210A1 carbon steel that had been compromised by wall thinning and the accumulation of fire and water-side scale deposits. Investigators determined that the tube failed due to prolonged caustic attack that led to ruptures in areas of high stress. The escaping steam eroded the outer surface of the tube causing heavy loss of metal around the rupture points.

This article provides some new developments in elevated-temperature and life assessments. It is aimed at providing an overview of the damage mechanisms of concern, with a focus on creep, and the methodologies for design and in-service assessment of components operating at elevated temperatures. The article describes the stages of the creep curve, discusses processes involved in the extrapolation of creep data, and summarizes notable creep constitutive models and continuum damage mechanics models. It demonstrates the effects of stress relaxation and redistribution on the remaining life and discusses the Monkman-Grant relationship and multiaxiality. The article further provides information on high-temperature metallurgical changes and high-temperature hydrogen attack and the steps involved in the remaining-life prediction of high-temperature components. It presents case studies on heater tube creep testing and remaining-life assessment, and pressure vessel time-dependent stress analysis showing the effect of stress relaxation at hot spots.