Welded steel storage vessels used to hold mildly alkaline solution were produced in exactly the same manner from deep-drawn aluminum-killed SAE 1006 low-carbon steel sheet. After the cylindrical shell was drawn, a top low-carbon steel closure was welded to the inside diameter. The containers were then filled with the slightly alkaline solution, pressurized, and allowed to stand under ambient conditions. A small number, less than 1%, were returned because they began to leak in service. Inspection revealed general corrosion and pitting on the inner surfaces. However, other tanks that experienced the same service conditions developed no corrosion. Corrosion was linked to forming defects that provided sites for localized corrosion, and to lack of steam drying after cleaning, which increased susceptibility to general corrosion.

A power plant using two steam generators (vertical U-tube and shell heat exchangers, approximately 21 m (68 ft) high with a steam drum diameter of 6 m (20 ft)) experienced a steam generator tube rupture. Each steam generator contained 11,012 Inconel alloy 600 (nickel-base alloy) tubes measuring 19 mm OD, nominal wall thickness of 1.0 mm (0.042 in.), and average length of 18 m (57.75 ft). The original operating temperature of the reactor coolant was 328 deg C (621 deg F). A tube removal effort was conducted following the tube rupture event. Investigation (visual inspection, SEM fractographs, and micrographs) showed evidence of IGSCC initiating at the OD and IGA under ridgelike deposits that were analyzed and found to be slightly alkaline to very alkaline (caustic) in nature. Crack oxide analysis indicated sulfate levels in excess of expected values. The analysis supported the conclusion that that the deposits formed at locations that experienced steam blanketing or dryout at the higher levels of the steam generators. Recommendations included steam generator water-chemistry controls, chemical cleaning, and reduction of the primary reactor coolant system temperature.

Within the first few months of operation of an 8 km (5 mile) long 455 mm (18 in.) diam high-pressure steam line between a coal-fired electricity-generating plant and a paper mill, several of the Inconel 600 bellows failed. The steam line operated at 6030 kPa (875 psi) and 420 deg C (790 deg F). Metallographic sections, energy-dispersive x-ray spectra, chemical analyses, tensile tests, and Auger microscope analyses showed the failed bellows met the specifications for the material. However, investigation also showed entire oxide thickness was contaminated with relatively large amounts of sodium, calcium, potassium, aluminum, and sulfur, alkali, alkali earth, and other contaminants that completely permeated even the thin oxides on the fracture surfaces. Additional investigation of the purity of the steam itself as reported by the power plant showed that corrosion and cracks were ultimately caused by the steam. While under normal operation, the steam's purity posed no problem to the material, during boiler cleaning operations, the generating plant had allowed contamination to get into the steam line.

A steam-condensate line (type 316 stainless steel tubing) began leaking after five to six years in service. The line carried steam condensate at 120 deg C (250 deg F) with a two hour heat-up/cool-down cycle. No chemical treatment had been given to either the condensate or the boiler water. To check for chlorides, the inside of the tubing was rinsed with distilled water, and the rinse water was collected in a clean beaker. A few drops of silver nitrate solution were added to the rinse water, which clouded slightly because of the formation of insoluble silver chloride. This and additional investigation (visual inspection, and 250x micrograph etched with aqua regia) supported the conclusion that the tubing failed by chloride SCC. Chlorides in the steam condensate also caused corrosion of the inner surface of the tubing. Stress was produced when the tubing was bent during installation. Recommendations included providing water treatment to remove chlorides from the system. Continuous flow should be maintained throughout the entire tubing system to prevent concentration of chlorides. No chloride-containing water should be permitted to remain in the system during shutdown periods, and bending of tubing during installation should be avoided to reduce residual stress.

Leaks developed at random locations in aluminum brass condenser tubes within the first year of operation of a steam condenser in a nuclear power plant. One failed tube underwent scanning electron microscopy surface examination and optical microscope metallography. It was determined that the tube failed from crevice corrosion under seawater deposits that had formed on the inner surface. Mechanical cleaning of the condenser tubes every 6 months and installation of intake screens of smaller mesh size were recommended.

Several waterwall tubes in a power station boiler failed after ten years of service. The boiler is a suspension type equipped with 30 IK boxes where retractable soot blowers are inserted to clean the inside of the boiler using high-pressure steam. The tubes, which operate at 693 deg F (367 deg C) and 2935 psi (20.5 MPa), failed near the IK boxes as a result of thermal fatigue. Thermal fatigue damage was accelerated by repetitive exposure to water droplets from the soot blower and the associated rapid cooling.

A 44.5 mm (1.75 in.) diam type 321 stainless steel seamless tube in a power-generating turbine failed after 19,000 h in service. The tube was used to carry a mixture of approximately 25% steam and 75% hot air. Three fractured pieces and part of the tube containing the mating fracture surface were examined. Both fractographic and metallographic features revealed that the failure was by thermal fatigue caused by the presence of biaxial thermal stresses on the inner surface of the tube. It was recommended that the steam and air be thoroughly mixed prior to entering the tube to decrease the temperature fluctuations of the inner surface.

Inhibited admiralty brass (UNS C44300) condenser tubes used in a natural-gas-fired cogeneration plant failed during testing. Two samples, one from a leaking tube and the other from an on leaking tube, were examined. Chemical analyses were conducted on the tubes and corrosion deposits. Stress-corrosion cracking was shown to have caused the failure. The most probable corrosive was ammonia or an ammonium compound in the presence of oxygen and water. All of the tubes were replaced.

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.

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.

Several nickel-base superalloy (UNS N06600) welded heat-exchanger tubes used in processing black liquor in a kraft paper mill failed prematurely. Leaking occurred through the tube walls at levels near the bottom tube sheet. The tubes had been installed as replacements for type 304 stainless steel tubes. Visual and stereoscopic examination revealed three types of corrosion on the inside surfaces of the tubes: uniform attack, deeper localized corrosive attack, and accelerated uniform attack. Metallographic analysis indicated that pronounced dissimilar-metal corrosion had occurred in the base metal immediately adjacent to the weld seam. The corrosion was attributed to exposure to nitric acid cleaning solution and was accelerated by galvanic differences between the tubes and a stainless steel tube sheet and between the base metal of the tubes and their dendritic weld seams. A change to type 304 stainless steel tubing made without dendritic weld seams was recommended.

A steam accumulator, constructed with 10.3 mm thick SA515-70 steel heads and an 8 mm thick SA455A steel shell, ruptured after about three years of service. The accumulator was used in plastic molding operations. An extensive lack of weld penetration in this the head-to-shell girth weld was revealed by laboratory examination. Some misalignment of the head to the shell because of radial displacement of the shell and head centerlines was observed which was found to result in excessive clearances between the two parts and a slight difference in the thicknesses of the parts. Transgranular fracture with occasional secondary branching was revealed. It was interpreted by stress analysis that a small amount of misalignment added to lack of penetration increased the stresses to near the tensile strength of the material. The failure was judged to be a short-cycle high-stress notch-fatigue failure.

An A-470 steel rotor disk was removed from the high-pressure portion of a steam turbine-powered compressor after nondestructive testing revealed cracks in the shoulder of the disk during a scheduled outage. Samples containing cracks were examined using various methods. Multiple cracks, primarily intergranular were found on the inlet and outlet faces along prior-austenite grain boundaries. The cracks initiated at the surface and propagated inward. Multiple crack branching was observed. Many of the cracks were filled with iron oxide. X-ray photoelectron spectroscopy indicated the presence of sodium on crack surfaces, which is indicative of NaOH-induced stress-corrosion cracking. Failure was attributed to superheater problems that resulted in caustic carryover from the boiler. Two options for disk repair, installing a shrink-fit disk or applying weld buildup, were recommended. Weld repair was chosen, and the rotor was returned to service; it has performed for more than 1 year without further incident.

A pair of steam generators operating at a pressurized water reactor site were found to be leaking near a closure weld. The generators were the vertical U-tube type, constructed from ASTM A302 grade B steel. The shell material exhibited high hardness values prior to confirmatory heat treatment, indicating high residual stresses in the area of the weld. All cracks were transgranular and were associated with pits on the inside surfaces of the vessels. It was concluded that the cracking was caused by a low-cycle corrosion fatigue phenomenon, with cracks initiating at areas of localized corrosion and propagating by fatigue. The cause of the pitting/cracking was related to the unit's copper species in solution.

After about four years of service, cracks appeared on the internal or process-side surfaces of four evaporator pans in a sugar concentrator. The pans consisted of a Mo stabilized austenitic stainless steel inner vessel surrounded by a mild steel steam jacket. Corrosion of the external surface had taken place in the form of confluent pitting over a band adjacent to the fillet weld which attached the pan to the blocking ring. Numerous cracks were present in this corroded zone. Microscopical examination of several specimens cut from the sample revealed that the internal cracks in the pan itself originated from the external side of the plate, i.e. from the region covered by the shrouding ring. They were predominantly of the transgranular type. Because the cracks were not of the intergranular type as usually found with weld decay, they were considered to be indicative of stress-corrosion cracking. Stresses responsible for the cracking resulted from weld contraction. The pans had been hosed down periodically with water from local boreholes to remove sugar from the external surfaces, which introduced the corrosive medium.

Three ASME SA106 grade B carbon steel feed water piping reducers from a pressurized water reactor showed indications of flaws near welds during ultrasonic testing. Further examination and testing indicated that the cracks resulted from a low-cycle corrosion fatigue phenomenon.

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.