Search Results for Condenser tubes, corrosion

Failures occurred in admiralty brass condenser tubes in a nuclear plant cooled by freshwater. About 2500 tubes had to be replaced over a span of six years. Investigation (visual inspection, chemical analysis, water chemistry (for both intake and outfall), and corrosion products in the operating system and on test coupons exposed to the operating environment) supported the conclusion that the failure was caused by microbe-initiated SCC. No recommendations were made.

An E-Brite /Ferralium explosively bonded tube sheet in a nitric acid condenser was removed from service because of corrosion. Visual and metallographic examination of tube sheet samples revealed severe cracking in the heat-affected zone between the outer tubes and the weld joining the tube sheet to the floating skirt. Cracks penetrated deep into the tube sheet, and occasionally into the tube walls. The microstructures of both alloys and of the weld appeared normal. Intergranular corrosion characteristic of end-grain attack was apparent. A low dead spot at the skirt / tube sheet joint allowed the Nox to condense and subsequently reboil. This, coupled with repeated repair welding in the area, reduced resistance to acid attack. Intergranular corrosion continued until failure. Recommendations included changing operating parameter inlet to prevent HNO3 condensation outside the inlet and replacement of the floating skirt with virgin material (i.e., material unaffected by weld repairs).

Several tubes in a 35 m 2 (115 ft 2 ) type 316 stainless steel shell-and-tube condenser leaked unexpectedly in an organic chemical plant that produces vinyl acetate monomer. Leaks were discovered after 5 years of operation and relocation of the condenser to another unit in the same plant. Examination of tubes and tube sheets revealed pitting damage on the OD surface. Some of the pits had penetrated fully, resulting in holes. Inside diameter surfaces were free of corrosion. Macro- and microexaminations indicated that the tubes had been properly manufactured. Pitting was attributed to stagnant water on the shell side. It was recommended that the surfaces not be kept in contacts with closed stagnant water for appreciable lengths of time.

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.

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.

An aluminum brass seawater surface condenser failed due to pitting after less than one year of service. Large pits filled with a green deposit were evidenced under the nonuniform black scale present over the entire inside surface of the tube. The black deposit was identified as primarily copper sulfide, with zinc and aluminum sulfides while the green deposit was revealed to be copper chloride. The combination of sulfide and chloride attack on the tubes was concluded to have resulted in the failure. Injection of ferrous sulfate upstream of the condenser which could aid the formation of protective oxide films was recommended.

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.

Tubes in heat exchangers, made of copper alloy C44300 and used for cooling air failed after 5 to six years of service. Air passed over the shell-side surface of the tubes and was cooled by water flowing through the tubes. Water vapor in the air was condensed (pH 4.5) on the tube surfaces during the cooling process. Air flow over the tubes reversed direction every 585 mm as a result of baffling placed in the heat exchangers. An uneven ridgelike thinning and perforation of the tube wall on the leeward side of the tube was revealed by visual examination. Undercut pits on the outer surface of the tube were revealed by metallographic examination of a cross section of the failed area. Impingement attack which led to perforation was revealed by both the ridgelike appearance of the damaged area and the undercut pitting. The heat exchanger was retubed with tubes made of aluminum bronze (copper alloy C61400).

Several type 304L (UNS S30400) stainless steel seamless tubes in a high-pressure synthesis gas cooler condensing ammonia in a fertilizer plant leaked in an unexpectedly short time. Representative samples of the tubes were subjected to chemical analysis, hardness tests, and optical microscopy examination. The tests revealed that the tubes conformed to specification. Crack morphology indicated stress-corrosion cracking by chlorides present in the cooling water. Use of a duplex stainless steel (for example, UNS S32304 S31803) as a tube material was recommended.

A failure occurred in buried brass (92% Cu, 8% Zn) piping used to carry drinking water in wet clay soil after less than two years in service. Investigation (visual inspection, chemical analysis of both the pipe surface and water, and a comparison of the corrosion failure of power station condenser tubing cooled by seawater for two copper alloys, an aluminum brass alloyed with arsenic (UNS C68700, ASTM B111, or Cu-Zn-20Al DIN17660), and a cupronickel 70-30 alloy with iron added (C71500, ASTM B111, or Cu-Ni-30Fe DIN17665)) supported the conclusion that the failure was caused by microbial induced corrosion by sulfate-reducing bacteria. No recommendations were made.

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 resistance-welded carbon steel superheater tube made to ASME SA-276 specifications failed by pitting corrosion and subsequent perforation, which caused the tube to leak. The perforation was found to have occurred at a low point in a bend near the superheater outlet header. It was found that the low points of the superheater tubes could not be completely drained during idle periods. Water-level marks were noticed on the inside surface above the area of pitting. It was revealed by microscopic examination that localized pitting had resulted from oxidation. It was concluded that water contained in the tube during shutdowns had accumulated and cumulative damage due to oxygen pitting resulted in perforation of one of the tubes. Filling the system with condensate or with treated boiler water was suggested as a corrective action. Alkalinity was suggested to be maintained at a pH of 9.0 and 200 ppm of sodium sulfite should be added to the water.

Severe pitting corrosion of a carbon steel tube was observed in the air preheater of a power plant, which runs on rice straw firing. Approximately 1450 tubes were removed from Stage 3 of the preheater (air inlet and flue gas outlet) due to corrosion and local bursting. Samples from Stage 2 (where corrosion was low) and Stage 3 (severe corrosion) were taken and subjected to visual inspection, SEM, x-ray diffraction, microhardness measurement, and chemical and microstructural analysis. It was determined that extended non-operation of the plant resulted in the settlement of corrosive species on the tubes in Stage 3. The complete failure of the tube occurred due to diffusion of these elements into the base metal and precipitation of potassium and chlorine compounds along the grain boundaries, with subsequent dislodging of grains. The nonmetallic inclusions acted as nucleating sites for local pitting bursting. Nonuniform heat transfer in Stage 3 operation accelerated the selective corrosion of front-end tubes. The relatively high heat transfer in this stage resulted in condensation of some corrosive gases and consequent corrosion. Continuous operation of the plant with some precautions during assembly of the tubes reduced the corrosion problem.

Eddy current inspection was performed on a vertical evaporator unit (that contained 180 tubes) used in a chemical processing plant. It was advised that the tube material was type 316 stainless steel. The shell-side fluid was condensate and gaseous methylene chloride, while the tube-side fluid was contaminated liquid methylene chloride. More than 100 tubes exhibiting severe outer surface pitting and cracklike indications near each tube sheet were revealed during eddy current inspection. It was observed that the indications correlated with rust-stained, pitted, and cracked areas on the outer surfaces. The cracking was revealed by metallographic examination to have initiated from the outer surface, frequently at pits, and penetrated the tube wall in a transgranular, branching fashion. The crack features were characteristic of chloride stress-corrosion cracking. A change in tube material was recommended to avoid future failures and loss of service.

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.

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.

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.

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.