High-temperature corrosion can occur in numerous environments and is affected by various parameters such as temperature, alloy and protective coating compositions, stress, time, and gas composition. This article discusses the primary mechanisms of high-temperature corrosion, namely oxidation, carburization, metal dusting, nitridation, carbonitridation, sulfidation, and chloridation. Several other potential degradation processes, namely hot corrosion, hydrogen interactions, molten salts, aging, molten sand, erosion-corrosion, and environmental cracking, are discussed under boiler tube failures, molten salts for energy storage, and degradation and failures in gas turbines. The article describes the effects of environment on aero gas turbine engines and provides an overview of aging, diffusion, and interdiffusion phenomena. It also discusses the processes involved in high-temperature coatings that improve performance of superalloy.

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.

Gas turbines and other types of combustion turbomachinery are susceptible to hot corrosion at elevated temperatures. Two such cases resulting in the failure of a gas turbine component were investigated to learn more about the hot corrosion process and the underlying failure mechanisms. Each component was analyzed using optical and scanning electron microscopy, energy dispersive spectroscopy, mechanical testing, and nondestructive techniques. The results of the investigation provide insights on the influence of temperature, composition, and microstructure and the contributing effects of high-temperature oxidation on the hot corrosion process. Preventative measures are also discussed.

The failure of T12 reheater tubes that had been in service for only 3000 h was investigated. The thickness of the tubes was visibly reduced by heavy oxidation corrosion on the inner and outer walls. The original pearlite substrate completely decomposed. Uniform oxide scale observed on the inner wall showed obvious vapor oxidation corrosion characteristics. Corrosion originated in the grain boundary, and selective oxidation occurred due to ion diffusion in the substrate. The layered oxide scale on the inner wall is related to the different diffusion rates for different cations. Exposure to high temperature corrosive flux accelerated the corrosion on the outer wall. Microstructure degradation and the corrosion characteristics observed indicate that the tubes failed primarily because of overheating, which is confirmed by calculations.

Cracking was found in the heads on large Yankee dryers, large, cylindrical, rotating, pressurized, high-temperature, cast iron pressure vessels (ASME Boiler and Pressure Vessel Code Section VIII, Rules for Construction of Pressure Vessels), used to remove moisture from sheets of tissue paper during manufacturing. The typical components consist of a cast iron shell, two cast iron concave heads, and a large cast iron internal center stay attached to journals. The heads are attached to the shell and center stay with high-strength bolts. FEA and metallurgical investigation supported the conclusion that the cracking was caused by an unexpected type of load placed on the machine, namely corrosion product buildup at the head/shell interface causing the joint to displace open. It was also found that compressive bolting loads could slightly open the head/shell interface at the periphery. Recommendations included design changes in the head/shell joint, and detailed preventive maintenance inspection procedures were also suggested.

After four months at a temperature of 400 to 5000 C, pipes at a gas generating plant were so heavily eroded they had to be replaced. Three sections of pipe, from different locations, were analyzed to determine whether mechanical wear or corrosion caused the damage. Samples of corrosion product from each pipe section were analyzed for carbon, sulfur, and iron and were found to consist mainly of iron sulfide mixed with soot and rust. The damage resulted from a high content of hydrogen sulfide in the gas (6% CO2, 20% CO, 8 to 12% H2, 0.5 to 1.5% CH4, remainder N2). To process the coal in question, the pipes material should be a heat-resistant steel that contains more chromium and has greater resistance to hydrogen sulfide.

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.

An Incoloy 800H (UNS N08810) transfer line on the outlet of an ethane-cracking furnace failed during decoking of the furnace tubes after nine years in service. A metallographic examination using optical and scanning electron microscopy as well as energy-dispersive x-ray spectroscopy revealed that the failure was due to sulfidation. The source of the sulfur in the furnace effluent was either dimethyl disulfide, injected into the furnace feed to prevent coke formation and carburization of the furnace tubes, or contamination of the feed with sulfur bearing oil.

Aluminide-coated and uncoated IN-713 turbine blades were returned for evaluation after service in a marine environment because of severe corrosion. Based on service time, failure of these blades by corrosive deterioration was considered to be premature. Analysis (visual inspection, 2.7x micrographic examination on sections etched with ferric chloride and hydrochloric acid in methanol) supported the conclusions that the blades failed by hot-corrosion attack. Variation in rate of attack on coated blades was attributed to variation in integrity of the aluminide coating, which had been applied in 1966, when these coatings were relatively new. It is evident that maintaining the integrity of a protective coating could significantly increase the life of a nickel-base alloy blade operating in a hot and corrosive environment.

The circumstances surrounding the in-service failure of a cast Ni-base superalloy (Alloy 713LC) second stage turbine blade and a cast and coated Co-base superalloy (MAR-M302) first stage air-cooled vane in two turbine engines used for marine application are described. An overview of a systematic approach, analyzing the nature of degeneration and failure of the failed components, utilizing conventional metallurgical techniques, is presented. The topographical features of the turbine blade fracture surface revealed a fatigue-induced crack growth pattern, where crack initiation had taken place in the blade trailing edge. An estimate of the crack-growth rate for the stage II fatigue fracture region coupled with the metallographic results helped to identify the final mode of the turbine blade failure. A detailed metallographic and fractographic examination of the air-cooled vane revealed that coating erosion in conjunction with severe hot-corrosion was responsible for crack initiation in the leading edge area.

Some examples of equipment failures involving high temperature operation are presented. They include some steam generator superheater components and a pump shaft that should not have been at high temperature. Metallographic analysis is used to determine the causes of failure in each case.

Brief overheating of the 89 mm OD 6.4 mm wall thickness titanium heater tubes (ASTM B337, grade 2) was caused by a flow stoppage in a leach heater. Blue-tinted areas and patches of flaky white, yellow, and brown oxide scale was revealed on visual examination. It was disclosed by subjecting the overheated tube to a flattening test that the tube no longer met ASTM B 337 specifications. Large grain size and numerous needlelike hydride particles were disclosed in the microstructure of the overheated tube. Heating to approximately 815 deg C was revealed by the presence of the flaky oxide and increased grain size. Hydrogen and oxygen absorption was revealed by the presence of hydrides and the shallow surface embrittlement and thus susceptibility to cracking at ambient temperatures was observed. It was concluded that the titanium tubes were embrittled due to overheating the tubes and the severe surface embrittlement resulted from oxygen absorption which made the surface layers susceptible to cracking under start up and shutdown. Replacement tubes made of a heat-resistant alloy (e.g., Hastelloy C-276) were recommended.

A failure analysis was conducted in late 1996 on two rolls that had been used in the production of iron and steel powder. The rolls had elongated over their length such that the roll trunnions had impacted with the furnace wall refractory. The result was distortion and bowing of the roll bodies which necessitated their removal from service. The initial analysis found large quantities of nitrogen had been absorbed by the roll shell. Further research indicated nitrogen pickup accounted for 3% volumetric growth for every 1% by weight nitrogen absorption. This expansion was sufficient to account for the dimensional change observed in the failed rolls. This paper details the failure analysis and resulting research it inspired. It also provides recommendations for cast material choice in highly nitriding atmospheres.

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.

An aircraft engine in which an in-flight fire had occurred was dismantled and examined. A bracket assembly fabricated from 2024 aluminum, one of several failed components, was of prime interest because of apparent heat damage. Scanning electron microscopy was used to compare laboratory-induced fractures made at room and elevated temperatures with the bracket failure. The service failure exhibited grain separation and loss of delineation of the grain boundaries due to melting. SEM revealed deep voids between grains and tendrils that connected grains, which resulted from surface tension during melting. Microscopic examination of polished, etched section through the fractured surface verified intergranular separation and breakdown of grain facets. The absence of any reduction of thickness on the bracket assembly at the point of fracture, along with evidence of intense heat at this point, indicated that little stress had been applied to the part. Comparisons of the service failure and laboratory-induced failures in conjunction with macroscopic and metallographic observations showed that the bracket assembly failed because an intense, localized flame had melted the material.

A coil made of a nickel-chromium alloy (Material No. 2.4869) with approx. 80Ni and 20Cr had burned through after a brief period of operation as a heating element in a brazing furnace. The protective atmosphere consisted of an incompletely combusted coal gas. Furnace temperature reached 1150 deg C. This type of selective oxidation at which the easily oxidized chromium burns, while the nickel is not attacked, is caused by mildly oxidizing gases and is sometimes designated as green rot. Under these conditions, chromium-containing steels and alloys whose oxidation resistance is based upon formation of tight oxide layers are not stable.

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.

High-chromium steel pipes 42.25 x 3.25 mm from a blast furnace gas fired recuperator for the preheating of air were heavily oxidized and perforated in places. It was found that the blast furnace gas had a high sulfur content. Both the carburization and the formation of sulfide proved that in addition, from time to time at least, combustion was incomplete and the operation was carried out in a reducing atmosphere, with the result that oxygen deficiency prevented the formation or maintenance of a protective surface layer on the external surface of the pipes. The sulfur would probably not have damaged the nickel-free steel used here at the given temperatures if it had been present as sulfur dioxide in an oxidizing atmosphere. The damage was therefore caused primarily by an incorrectly conducted combustion process.

Severely reduced wall thickness was encountered at the liquid line of a lead-bath pan that was used in a continuous strip or wire oil-tempering unit. Replacement of the pan was necessary after six months of service. The pan, 6.9 m (22.5 ft) long, 0.6 m (2 ft) wide, and 38 cm (15 in.) deep with a 2.5-cm (1-in.) wall thickness, was a type 309 stainless steel weldment. Operating temperatures of the lead bath in the pan ranged from 805 deg C (1480 deg F) at the entry end to 845 deg C (1550 deg F) at the exit end. Analysis (visual inspection. metallographic analysis, moisture testing, and etched micrographs using Murakami's reagent) supported the conclusions that thinning of the pan walls at the surface of the molten lead resulted from using coke of high moisture content and from the low fluctuating coke level. Recommendations included reducing the supply of oxygen attacking the grain boundaries and the hydrogen that readily promoted decarburization with the use of dry (2 to 3% moisture content) coke. Maintaining a thick layer of coke over the entire surface of molten lead in the pan would exclude atmospheric oxygen from the grain boundaries.

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.