A heat exchanger made of a pipe in which oil was heated from the outside from approximately 90 deg C to 170 deg C, by superheated steam of about 8 to 10 atmospheres had developed a leak at the rolled joint of the pipe and pipe bottom. The pipes were supposed to be made from St 35.29 steel and annealed at the rolled joint to 100 mm length. The outer pipe surface was strongly pitted by corrosion all around the rolled joint. In the vicinity of the steam chamber the pipe wall had oxidized through from the exterior to the interior at one spot. Adjoining this spot, grooves caused by erosion were noticeable. This was a typical case of crevice corrosion. The rolled joint evidently was not entirely tight, so that saturated steam condensate could penetrate into the gap.

A microstructural analysis has been made of a burner nozzle removed from service in a coal gasification plant. The nozzle was a casting of a Co-29wt%Cr-19wt%Fe alloy. Extensive hot corrosion had occurred on the surface. There was penetration along grain boundaries, and corrosion products in these regions were particularly rich in S, and also contained Al, Si, O, and Cl. The grain boundaries contained Cr-rich particles which were probably Cr23-C6 type carbides. In the matrix, corrosion occurred between the Widmanstatten plates. Particles were found between these plates, most of which were rich in Cr and O, and probably were Cr2-O3 oxides. Other matrix particles were found which were rich in Al, O, and S. The corrosion was related to these grain boundary and matrix particles, which either produced a Cr-depleted zone around them or were themselves attacked.

A carbon steel furnace tube which should have given good service for ten years ruptured after one year. The tube showed obvious swelling at the point of rupture, and the bulged surface of the tube was oxidized at a temperature far above the design temperature. There was little or no loss in wall thickness due to corrosion or scaling, and the tube wall was thinned to a knife edge at the rupture. Metallographic examination showed the condition of the material was satisfactory. The failure was mechanical in nature, typical of short time creep rupture. The localized oxidation indicated improper furnace operation or blockage of the tube. The furnace was checked and found to have a burner tip out of order. After the tip was repaired, localized overheating was minimized and further premature failures did not occur.

Over a period of about one year, three RA 330 alloy salt pots from a single heat-treating plant were submitted to failure analysis. All of the pots, which had 9.5 mm thick walls, were used primarily to contain neutral salts at temperatures from about 815 to 900 deg C (1500 to 1650 deg F). However, some cyaniding was also performed in these pots, which, when not in use, were idled at 760 deg C (1400 deg F). It was reported that sludge was removed from the bottom of the pots once a day. Normal pot life varied from about 6 to 20 months. The pots were removed from the furnace, visually inspected, and rotated 120 deg every three weeks to ensure that no single location was overheated for a prolonged period of time. Analysis (visual inspection, chemical analysis, metallographic examination, and x-ray analysis, 60x micrograph etched with 10% oxalic acid) supported the conclusion that the cause of failure of each of the three salt pots was severe intergranular corrosion accompanied by substantial chromium depletion. No recommendations were made.

Three radiant tubes, made of three different high-temperature alloys, were removed from a carburizing furnace after approximately eight months of service when they showed evidence of failure by collapsing (telescoping) in a region 30 cm (12 in.) from the tube bottoms in the vicinity of the burners. The tubes had an original wall thickness of 3.0 mm (0.120 in.) and were made of three different alloys: the first was Hastelloy X; the second alloy was RA 333, a wrought nickel-base heat-resistant alloy; and the third was experimental alloy 634, which contained 72% Ni, 4% Cr, and 3.5% Si. The three radiant tubes had been operated at a temperature of about 1040 deg C (1900 deg F) to maintain furnace temperatures of 900 to 925 deg C (1650 to 1700 deg F). Analysis (visual inspection and micrographic examination) supported the conclusion that all three tubes failed by corrosion. Recommendations included replacing the material with an alloy, such as RA 333, with a higher chromium content and with an additional element, like silicon, resistant to carburization-oxidation.

One of 14 vertical radiant tubes (RA 333 alloy) in a heat-treating furnace failed when a hole about 5 x 12.5 cm (2 x 5 in.) corroded completely through the tube wall. The tube measured 183 cm (72 in.) in length and 8.9 cm (3 in.) in OD and had a wall thickness of about 3 mm (0.120 in.). Failure occurred where the tube passed through the refractory hearth (floor) of the furnace. Although the furnace atmosphere was neutral with respect to the work, it had a carburizing potential relative to the radiant tubes. Analysis (visual inspection, 250x spectroscopic examination of specimens etched with mixed acids, metallographic examination, and chemical analysis) supported the conclusions that the premature failure of the tube by perforation at the hearth level resulted from (1) corrosion caused by sulfur contamination from the refractory cement in contact with the tube and (2) severe local overheating at the same location. Recommendations included replacing all tubes using a low sulfur refractory cement in installation and controlling burner positioning and regulation more closely to avoid excessive heat input at the hearth level.

Three samples from a ruptured 316 stainless steel tube were examined. The tube, 114 mm OD, wall thickness 8.00 mm, with 13 mm thick 321 stainless steel fins welded to the outer surface of the tube, was part of a heater through which sour gas, containing methane plus H2S and CO, passed at 1150 psig. The sour gas was heated to 600 deg F by burners playing on the outside of the tube burning “sweet” gas plus air. The inner and outer surfaces of all samples showed evidence of corrosive attack. Electron probe microanalysis showed the corrosion products contained sulfur with iron, together with nickel to a lesser extent. Local thinning, cavitation, and ductile deformation markings associated with the unmatched sample taken from the center of the fire showed the tube ruptured as a result of overheating. Overheating while the temperature recorder was off the chart caused severe loss of tube strength, resulting in ductile rupture. The minimum overheating temperature could be deduced at around 1200 deg F due to the presence of a eutectic observed metallographically within the surface corrosion products.

A bent Ni-Cu Monel 400 alloy tube, which operated as part of a pipeline in a petrochemical distillery, failed by through-thickness cracking. The pipeline was used to carry a stream of gaseous hydrocarbons containing hydrochloric acid (HCl) into a reaction tower. The tower provided a caustic solution (NaOH) to remove HCl from the stream, before the latter was directed to a burner. Metallographic examination showed that the cracks were intergranular and were frequently branched. Although nominal chemical composition of the component was found within the specified range, energy dispersive x-ray analysis (EDXA) indicated significant segregation of sulfur and chlorine along the grain boundaries. Failure was attributed to hypochlorous-acid (HClO)-induced stress-corrosion cracking (SCC). The HClO was formed by the reaction of HCl with atmospheric O 2 that entered the tube during shutdowns and startups. Residual stresses, originating from in situ bend forming of the tube during assembly of the line, provided a driving force for crack growth, and the segregation of sulfur on grain boundaries made the material more susceptible to cracking.

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.

A portable propane container with a name-plate soldered onto it exploded in service. When the vessel was inspected afterwards, it was found to have developed a crack in the top end plate. A portion of the end plate cut out to include the midlength and one termination of the crack was examined microscopically. This revealed that the crack was associated with intergranular penetration by molten metal. The microstructure in general was indicative of a good-quality mild steel. It was evident from that solder that was responsible for the penetration and that fused brass from the hand wheel had not played any part. Tensile stress was present at the time of the failure sufficiently high to enable solder penetration to take place. The use of soft solder as a medium for attaching name-plates directly on to stressed steel parts is not recommended. It would be preferable to use a welded-on patch plate or to employ one of the high-strength, non-metallic adhesives.

Severe pitting was found on the internal surfaces of SA-210 Grade C waterwall tubing of a coal-fired boiler at a cogeneration facility. Metallographic examination showed the pits to be elliptical, having an undercut morphology with supersurface extensions,. a type of pitting characteristic of acidic attack. Energy-dispersive X-ray spectroscope revealed the presence of chlorine in the pit deposits, indicating that the pitting was promoted by underdeposit chloride attack. The presence of copper in deposits on the internal surface of the tubing may have acted as a secondary factor. Acidic conditions may have formed during a low-pH excursion that reportedly occurred several years prior. To prevent future failures, severely damaged tubing must be replaced. Internal deposit buildup must be removed by chemical cleaning to prevent further pitting. Water quality needs continued monitoring and maintenance to ensure that another low-pH excursion does not occur.

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.

A material is flammable if it is subject to easy ignition and rapidly flaming combustion. The plastics that are most widely used are the least expensive and tend to be the most flammable. This article describes the two basic approaches to improving the fire resistance of a polymeric material: modifying or substituting the basic polymer so that exposure to heat and oxygen will not produce rapid combustion, and using flame-retardant additives. It also provides an overview of the burning process and presents two flammability test methods.

A gas-fired, ASTM A-106 Grade B carbon steel vaporizer failed on three different occasions during attempts to bring the vaporizer on line. Dye penetrant examination indicated the presence of multiple packets of ductile cracks on the inside of the coil radius at the bottom of the horizontal axis coils. Visual examination of the inside of the tubing indicated the presence of a carbonaceous deposit resulting from decomposition of the heat-exchanging fluid. Subsequent metallographic examination and microhardness testing indicated that the steel was heated to a temperature above the allowable operating temperature for the fluid. The probable cause for failure is thermal fatigue due to the localized overheating. Flow conditions inside the tubing should be reexamined to ensure suitable conditions for annular fluid flow.

A steel pot used as crucible in a magnesium alloy foundry developed a leak that resulted in a fire and caused extensive damage. Hypotheses as to the cause of the leak included a defect in the pot, overuse, overheating, and poor foundry practices. Scanning electron microscopy, transmission electron microscopy, optical microscopy, and x-ray microanalysis in conjunction with dimensional analysis, phase diagrams and thermodynamics considerations were employed to evaluate the various hypotheses. All evidence pointed to an oxide mass in the area where the hole developed, likely introduced during the steelmaking process.

This article provides assistance to a failure analyst in broadening the initial scope of the investigation of a physical engineering failure in order to identify the root cause of a problem. The engineering design process, including task clarification, conceptual design, embodiment design, and detail design, is reviewed. The article discusses the design process at the personal and project levels but takes into consideration the effects of some higher level influences and interfaces often found to contribute to engineering failures.

The intent of this article is to assist the failure analyst in understanding the underlying engineering design process embodied in a failed component or system. It begins with a description of the mode of failure. This is followed by a section providing information on the root cause of failure. Next, the article discusses the steps involved in the engineering design process and explains the importance of considering the engineering design process. Information on failure modes and effects analysis is also provided. The article ends with a discussion on the consequence of management actions on failures.

Waterwall tube failure samples removed from a coal- and oil-fired boiler in service for 12 years exhibited localized underdeposit corrosion and hydrogen damage. EDS and XRD revealed that bulk internal deposits collected from the tubes contained metallic copper which can accelerate corrosion through galvanic effects and can promote hydrogen damage. Ultrasonic testing was recommended to locate tubes with severe gouging and corrosion, which are suspect locations for hydrogen damage. The source of the copper should be identified and future chemical cleaning of the boiler should address its presence in the waterwall tubes.

Two steam-methane reformer furnaces were subjected to short-time heat excursions because of a power outage, which resulted in creep bulging in the Incoloy 800 outlet pigtails, requiring complete replacement. Each furnace had three cells, consisting of 112 vertical tubes per cell, each filled with a nickel catalyst. The tubes were centrifugally cast from ASTM A297, grade HK-40 (Fe-25Cr-20Ni-0.40C), heat-resistant alloy. The tube was concluded after metallurgical inspection to have failed from creep rupture (i.e., stress rupture). A project for detecting midwall creep fissuring was instigated as a result of the failure. It was concluded after laboratory radiography and macroexamination that if the fissure were large enough to show on a radiograph, either with or without the catalyst, the tube could be expected to fail within one year. The set up for in-service radiograph examination was described. The tubes of the furnace were radiographed during shut down and twenty-four tubes in the first furnace and 53 in the second furnace showed significant fissuring. Although, radiography was concluded to be a practical technique to provide advance information, it was limited to detecting fissures caused by third-stage creep in tubes because of the cost involved in removing the catalysts.