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.

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.

Dezincification is a particular form of corrosive attack which may occur in a variety of environments and to which some brasses are susceptible. It is favored by waters having a high oxygen, carbon dioxide, or chloride content, and is accelerated by elevated temperatures and low water velocities. In the present study, steam turbine condenser tubes had to be renewed after 25 years of service. The tubes were nominally of 70:30 brass. The appearance of a typically corroded one showed uniform dezincification attack on the bore, extending from one-half to two-thirds through the tube wall thickness.

A tubular heat exchanger in a refinery reformer unit leaked after one month of service. The exchanger contained 167 type 304 stainless steel U-bent integral-finned tubes. Cracks in the tube wall were revealed during examination. Hardness of the tube was found to be 30 HRC at the inside surface and up to 40 HRC at the base of the fin midway between the roots which indicated that the fins were cold formed and not subsequently annealed thus susceptible to SCC because of a high residual stress level. It was revealed by metallographic examination that the fracture was predominantly by transgranular branched cracking and had originated from the inside surface. It was concluded that the tubes failed in SCC caused by chlorides in the presence of high residual stresses. The finned tubes were ordered in the annealed condition as a corrective measure.

Leaks developed in 22 admiralty brass condenser tubes. The tubes were part of a condenser that was being used to condense steam from a nuclear power plant and had been in operation for less than 2 years. Analysis identified three types of failure modes: stress-corrosion cracking, corrosion under deposit (pitting and crevice), and dezincification. Fractures were transgranular and typical of stress-corrosion cracking. The primary cause of the corrosion deposit was low-flow conditions in those parts of the condenser where failure occurred. Maintenance of proper flow conditions was recommended.

A superheater in a generator produced 80 t/h of steam at 400 deg C and 41 kPa. Failure took place at the connection from the collector to the vent line used during start up. The material of construction was carbon steel, and the unit had 240,000 h of operation at the time of failure, with 99 shutdowns. Widespread cracking on the inside was apparent, the most severe cracking being some distance from the nozzle connection in a downstream direction. Widespread cracking and pitting were observed also at the connections to the safety valve and soot blower. Pitting was most apparent on the downstream sides of the openings in the shell. In all the damaged areas the mechanism of failure involved surface pitting and subsequent SCC. This failure showed the problems that can develop where there are long lines in which condensation may occur and return periodically to a superheater or other hot component. In this particular case, control of dissolved solids in the boiler feedwater may have been inadequate.

The bottom flange of a vertical pipe coupled to an isolating valve in a steam supply line to a turbine failed. Steam pressure was 1,500 psi and the temperature 416 deg C (780 deg F). Multiple cracking occurred in the bore of the flange. A quarter-segment was cut out and examined. The cracks were located in the part of the flange that formed a continuation of the pipe bore. The majority of them originated at the end of the flange bore and extended axially along the pipe and radially across the flange face. Magnetic crack detection revealed a further number of cracks in the weld deposit. While the fracture in the weld metal was of the ductile type exhibiting a fine fibrous appearance, that in the flange material was of the cleavage type. Microscopic examination revealed that the cracks were blunt-ended fissures of the type characteristic of corrosion-fatigue. It was concluded that cracking was due to corrosion-fatigue, which arose from the combined effect of a fluctuating tensile stress in the presence of a mildly corrosive environment.

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.

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.

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.

Examination of the header of the third superheater of a boiler producing 150 t/h of steam at 525 deg C and 118 kPa, disclosed extensive internal cracking at the connection to the tube joining this to a safety valve. Cracking was observed within the tube and in the thickness of the shell wall itself. The boiler had been in operation for approximately 160,000 h and was shut down for inspection when the cracking was detected. The material involved was 2.25 Cr, 1 Mo steel, and the unit had been subjected to 115 shutdowns. Initiation of the cracks was attributed to thermal shock, caused by the periodic return of condensate along the long connecting line (some 9 m long). Propagation of the cracks was due to thermal cycling, together with periodic pressure cycles, producing growth by low cycle fatigue. This was aided by corrosion within the cracks and by the wedging action caused by corrosion deposits at their tips. The failure suggests control of dissolved solids in the boiler feedwater may have been inadequate.

A brass elbow that formed one termination of a steam heating coil failed adjacent to the brazed connection after ten years of service. Chemical analysis showed that the elbow was made from a 60-40 CuZn brass containing 3% lead and 1% tin, a typical alloy used for the manufacture of components by the hot stamping process. Microscopic examination indicated failure from dezincification. The fact that the screwed end was not affected indicated that the trouble was not caused by the condensate, which flowed through the elbow, but originated from the water heated in the vessel. The helical mode of the cracking was probably due to the torsional stresses which would be imposed on the elbow by thermally induced movements of the coil in service.

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 nuclear steam-generator vessel constructed of 100-mm thick SA302, grade B, steel was found to have a small leak. The leak originated in the circumferential closure weld joining the transition cone to the upper shell. The welds had been fabricated from the outside by the submerged arc process with a backing strip. The backing was back gouged off, and the weld was completed from the inside with E8018-C3 electrodes by the shielded metal arc process. Striations of the type normally associated with progressive or fatigue-type failures including beach marks that allowed tracing the origin of the fracture to the pits on the inner surface of the vessel were revealed. Copper deposits with zinc were revealed by EDS examination of discolorations. Pitting was revealed to have been caused by poor oxygen control in the steam generators and release of chloride into the steam generators. It was concluded by series of controlled crack-propagation-rate stress-corrosion tests that A302, grade B, steel was susceptible to transgranular stress-corrosion attack in constant extension rate testing with as low as 1 ppm chloride present. It was recommended to maintain the coolant environment low in oxygen and chloride. Copper ions in solution should be eliminated or minimized.

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.

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.