Search Results for Steam drums

During the inspection of a boiler containing cracks at the superheater header connection, cracking also was detected within the main steam drum. This was fabricated from a Mn-Mo-V low-alloy steel. It operated with water and saturated steam at approximately 335 deg C. Cracking was detected at the nozzles connecting the tubes for the entry of steam and hot water to the drum, at the downcomers, and at the connection to the safety valve. All cracks had a similar morphology, running in a longitudinal direction along the drum from the cutouts in the shell. All the cracks had developed under the influence of the hoop stress and were associated with the locally increased stress levels relating to the cutouts at nozzle and pipe connections. At their ends the cracks were filled with corrosion products, and their surfaces were seen to be very irregular. The process of crack growth was not due to fatigue only but can most probably be attributed to corrosion fatigue. The boiler steam drum design should be reviewed to reduce the local level of stress at the shell-nozzle connections.

Tubes in a marine boiler on a new ship failed after brief service lives. Circumferential brittle cracking was found to occur in the carbon-molybdenum steel tubes near the points where the tubes were attached to the steam drum. Fatigue striations were revealed by examination of fracture surfaces by electron microscopy at high magnification. Fatigue failures were concluded to be caused by vibrations resulting from normal steam flow at high steam demand. Too rigid support near the steam drum resulted in concentration of vibratory strain in the regions of failure. The method of supporting the tubes was changed to reduce the amount of restraint and the strain concentration.

Two identical “D” tube package boilers, installed at separate plants, experienced a number of tube ruptures after relatively short operating times. The tubes, which are joined by membranes, experienced localized bulging and circumferential cracking along the fireside crown as a result of overheating and thermal fatigue. It was recommended that recent alterations to the steam-drum baffling be remodified to improve circulation in the boiler and prevent further overheating. Several thermocouples were attached to tubes in problem areas of the boiler to monitor the effects of the steam-drum modifications on tube wall temperatures.

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.

Gross wastage and embrittlement were observed in plain carbon steel desuperheaters in five new Naval power plants. The gross wastage could be duplicated in laboratory bomb tests using sodium hydroxide solutions and was concluded to be caused by free caustic concentrated by high heat flux. The embrittlement was shown to be caused by the flow of corrosion generated hydrogen which converted the cementite to methane which nucleated voids in the steel. A thermodynamic estimate indicated that a small amount of chromium would stabilize the carbides against decomposition by hydrogen in this temperature range, and laboratory tests with 2-14% Cr steel verified this.

Original carbon steel and subsequent replacement austenitic stainless steel superheater tube U-bend failures occurred in a waste heat boiler. The carbon steel tubes had experienced metal wastage in the form of caustic corrosion gouging, while the stainless steel tubes failed by caustic-induced stress-corrosion cracking. Sodium was detected by EDS in the internal deposits and the base of a gouge in a carbon steel tube and in the internal deposits of the stainless steel tube. The sodium probably formed sodium hydroxide with carryover moisture and caused the gouging, which was further aggravated by the presence of silicon and sulfur (silicates and sulfates). It was recommended that the tubes be replaced with Inconel 600 or 601, as a practical option until the carryover problem could be solved.

During the routine hydraulic pressure test of a boiler following modification, failure by leakage from the drum took place and was traced to a region where extensive multiple cracking had occurred. Catastrophic rupture or fragmentation of the vessel fortunately did not take place. Prior to the test, cracking was present already, extending up to 90% of the wall thickness. Analyses of brownish deposit material did not reveal the presence of any substances likely to cause stress-corrosion cracking of a Ni-Cu-Mo low-alloy steel.

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.

Numerous cracks observed on the surface of a forged A470 Class 4 alloy steel steam turbine rotor disc from an air compressor in a nitric acid plant were found to be the result of caustic induced stress-corrosion cracking (SCC). No material defects or anomalies were observed in the disc sample that could have contributed to crack initiation or propagation or secondary crack propagation. Chlorides detected in the fracture surface deposits were likely the primary cause for the pitting observed on the disc surfaces and within the turbine blade attachment area. It was recommended that the potential for water carryover or feedwater induction into the turbine be addressed via an engineering evaluation of the plant's water treatment procedures, steam separation equipment, and start-up procedures.

Caustic cracking is the term used to describe one of the forms in which stress-corrosion cracking manifests itself in carbon steels. In the present study, persistent leakage occurred after ten weeks of service from tube expansions in the steam and mud drum of a two-drum D type boiler, which failed to respond to repeated expansion. The leakage was traced to circumferential cracking in the portion of Fe-0.11C-0.46Mn-0.018S-0.011P tubes within the expanded region. Microscopic examination indicated that all cracks started from the outer surface of the tubes in the expanded portion. The form of cracking which was mostly intergranular. Examination at higher magnification disclosed that a selective attack had taken place on the carbide constituents of the pearlite grains. An alkaline deposit on the fireside surface of the tube resulted from the evaporation of boiler water which had found its way past the tube expansions. This indicated that this operation had not resulted in a satisfactorily tight joint.

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.

During a hydraulic test on one of the boilers in a range, leakage occurred from the lower surface of a horizontal S bend in the main steam pipe between the drum connector box and the junction valve. The pipe in question was 15 in. bore and had been in service for about 50 years. Specimens were prepared for microscopical examination to include the defective zone and a section through a circumferential crack. The defective zone was found to contain numerous inclusions of slag and oxides of globular form. Regions surrounding the inclusions were decarburized, the indications being that this region of the plate had been heated to an excessively high temperature. A corrosion-fatigue fissure was at one location, this having originated at the internal surface of the pipe and run into an inclusion in the defective zone. The failure resulted from the development of corrosion-fatigue fissures which originated at a zone containing defects introduced at the time of manufacture. These may have had their origin in the ingot from which the plate was rolled or, alternatively, be indicative of a zone which suffered overheating and local burning at the time the forge weld was made.

Tube failures occurred in quick succession in two boiler units from a bank of six boilers in a refinery. The failures were confined to the SAE 192 carbon steel horizontal support tubes of the superheater pack. In both cases, the failure was by perforation adjacent to the welded fin on the crown of the top tubes and located in an area near the upward bend of the tube. The inside of all the tubes were covered with a loosely adherent, black, alkaline, powdery deposit comprised mainly of magnetite. The corroded areas, however, had relatively less deposit. The morphology of the corrosion damage was typical of alkaline corrosion and confirmed that the boiler tubes failed as a result of steam blanketing that concentrated phosphate salts. The severe alkaline conditions developed most probably because of the decomposition of trisodium phosphate, which was used as a water treatment chemical for the boiler feed water.

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.

Two superheater tubes from a 6.2 MPa (900 psig) boiler failed in service because of creep rupture. One tube was carbon steel and the other was carbon steel welded to ASTM A213 Grade T22 (2.25Cr-1.0Mo) tubing. The failure in the welded tube occurred in the carbon steel section. Portions of the superheater were retubed five years previously with Grade 722 material. The failures indicated that tubes were exposed to long-term overheating conditions. While the carbon steel tube did not experience temperatures above the lower transformation temperature 727 deg C (1340 deg F), the welded tube did experience a temperature peak in excess of 727 deg C (1340 deg F). The long-term overheating conditions could have been the result of excessive heat flux and /or inadequate steam flow. In addition, the entire superheater bank should have been upgraded to Grade 722 material at the time of retubing.

A tube in a radiant superheater, the boiler of which is coal fired, failed by creep after 17 years of service. The failed tube was specified to be made of ASME SA-213, grade T-22. Measurable swelling of the tube diameter by about 2.4 mm and tube wastage caused by corrosion or erosion were observed. Log stress versus Larson-Miller Parameter (LMP) plots were produced to assess the remaining life of the superheater. It was revealed that the estimated operating temperature of 1060 deg F was higher than the estimated design temperature of 1000 deg F and that the tube wastage had increased the actual operating stress. Tube wastage and high operating temperatures hastened the failure. A better understanding of the material condition of this superheater was recommended to verify all the suspect hot tubes.

The center portions of two adjacent low-carbon steel boiler tubes (made to ASME SA-192 specifications) ruptured during a start-up period after seven months in service. It was indicated by reports that there had been sufficient water in the boiler two hours before start-up. The microstructure near the rupture edge was revealed by metallographic examination to consist of ferrite and acicular martensite or bainite. The microstructure and the observed lack of cold work indicated a temperature above the transformation temperature of 727 deg C had been reached. Swelling of the tubes was disclosed by the wall thickness and OD of the tubing. The tubes were concluded to have failed due to rapid overheating.