During a work over of an oil well, the 9% Ni steel production tubing parted three times as it was being pulled from the well. The tubing had performed satisfactorily for more than 30 years in the well A representative failure, a circumferential fracture in a connection, was analyzed. Reported to be a hydril CS connection, the pin end parted near the last threads. The external surface exhibited mechanical damage marks from the fishing operation. No signs of external corrosion or damage were detected. Visual surface examination revealed shear lips at the outside pipe, indicating that the fracture initiated at the inside surface and grew across the wall. Longitudinal cross sections revealed heavy corrosion damage to the inside pipe surface. Metallographic examination indicated that the tubing failed as a result of severe weakening from internal corrosion. Gray-colored corrosion deposits, which penetrated the pipe throughout the grain boundaries of the material and concentrated in the matrix in a layer near the inside surface of the pipe, were observed. The presence of H2S in the produced fluids and the appearance of the gray deposit indicated that the tube suffered H2S corrosion. Chemical analysis of the base metal and corrosion deposits did not detect iron or nickel sulfides, however Replacement of the remaining pipe strings according to a scheduled program was recommended. Because 9% Ni steel was not available, 13% Cr martensitic stainless steel was recommended as a replacement.

A failure of an aboveground storage tank occurred due to external corrosion of the tank floor. The liquid asphalt tank operated at elevated temperatures (approximately 177 deg C, or 350 deg F) and had been in service for six years. Cathodic protection (rectifiers) had been installed since start-up of the tank operation. It was noted, however, that some operational problems with the rectifier may have interrupted its protection. Investigation (visual inspection, on-site examination and testing, EDS analysis of scale deposits, and MIC testing of the soil) supported the conclusion that corrosion may have been caused by an interruption in cathodic protection. The effectiveness of cathodic protection on established microbial deposits is questionable. Recommendations included ultrasonically testing the tank floor and replacing portions based on the remaining wall thickness. Doubling the wall thickness of the floor plates was also recommended.

The outlet-piping system of a steam-reformer unit failed by extensive cracking at four weld locations. The welded system consisted of Incoloy 800 (Fe-32Ni-21Cr-0.05C) pipe and fittings. The exterior surfaces of the system were insulated with rock wool that did not contain weatherproofing. On-site visual examination and magnetic testing indicated severe external corrosion of most of the piping. The system showed extensive cracking in weld HAZ. One specimen indicated that corrosion extended to a depth of 3.2 mm and cracks were seen at the edge of the cover bead and in the HAZ of the weld. Metallographic examination showed that cracking was intergranular and that adjacent grain boundaries had undergone deep intergranular attack. Examination at higher magnification revealed heavy carbide precipitation, primarily at grain boundaries, indicating that the alloy had been sensitized, which resulted from heating during welding. Electron probe x-ray microanalysis showed the outside surface of the tube did not have the protective chromium oxide scale normally found on Incoloy 800. The inside surface of the tube had a thin chromium oxide protective scale. This evidence supported the conclusions that the deep oxidation greatly decreased the strength of the weld HAZ and cracking followed.

Four tanks made from type 304L stainless steel were removed from storage. Atmospheric corrosion on the outside of the tanks and pitting and crevice corrosion on the inside were visible. Metallographic examination revealed that the internal corrosion had been caused by crevices related to weld spatter and uneven weld deposit and by service water that had not been drained after hydrostatic testing. External corrosion was attributed to improper passivation. It was recommended that the surfaces be properly passivated and that, before storage, the interiors be rinsed with demineralized water and dried.

This article discusses the failure analysis of several steel transmission pipeline failures, describes the causes and characteristics of specific pipeline failure modes, and introduces pipeline failure prevention and integrity management practices and methodologies. In addition, it covers the use of transmission pipeline in North America, discusses the procedures in pipeline failure analysis investigation, and provides a brief background on the most commonly observed pipeline flaws and degradation mechanisms. A case study related to hydrogen cracking and a hard spot is also presented.

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.

A section of pipe in a hydrocarbon pipeline was found to be leaking. The pipeline was installed several decades earlier and was protected by an external coating of extruded polyethylene and a cathodic protection system. The failed pipe section was made from API 5L X46 line pipe steel, approximately 22 cm (8.7 in.) OD x 0.5 cm (0.2 in.) wall thickness, which was electric resistance welded along the longitudinal seam. The pressure at the time and location of the failure was 2760 kPa, which corresponds to 20% of the specified minimum yield strength. The cause of failure (based on visual inspection, magnetic particle inspection, stereoscopic analysis, scanning electron microscopy, tensile and hardness testing, and chemical analysis) was attributed to damage resulting from a lightning strike.

This article focuses on the mechanisms of microbiologically influenced corrosion as a basis for discussion on the diagnosis, management, and prevention of biological corrosion failures in piping, tanks, heat exchangers, and cooling towers. It begins with an overview of the scope of microbial activity and the corrosion process. Then, various mechanisms that influence corrosion in microorganisms are discussed. The focus is on the incremental activities needed to assess the role played by microorganisms, if any, in the overall scenario. The article presents a case study that illustrates opportunities to improve operating processes and procedures related to the management of system integrity. Industry experience with corrosion-resistant alloys of steel, copper, and aluminum is reviewed. The article ends with a discussion on monitoring and preventing microbiologically influenced corrosion failures.

A type 316 stainless steel pipe reducer section failed in service of bleached pulp stock transfer within 2 years in a pulp and paper mill. The reducer section fractured in the heat-affected zone of the flange-to-pipe weld on the flange side. The pipe reducer section consisted of 250 and 200 mm (10 and 8 in.) diam flanges welded to a tapered pipe section. The tapered pipe section was 3.3 mm (0.13 in.) thick type 316 stainless steel sheet, and the flanges were 5 mm (0.2 in.) thick CF8M (type 316) stainless steel castings. Visual and metallographic analysis indicated that the fracture was caused by intergranular corrosion/stress-corrosion cracks that initiated from the external surface of the pipe reducer section. Contributory factors were the sensitized condition of the flange and the concentration of corrosive elements from the bleach stock plant environment on the external surface. In the absence of the sensitized condition of the flange, the service of the pipe reducer section was acceptable. A type 316L stainless steel reducer section was recommended to replace the 316 component because of its superior resistance to sensitization.

Austenitic stainless steel (X 10 Cr-Ni-Mo-Ti 18 10, Material No. 1.4571) cooling coils were found leaking in 15 spots after eight weeks of service in an apparatus in which ammonium sulfide solution was converted into ammonium sulfate. The external temperature of the coil was approximately 175 deg C and it was cooled by water at 3 atm. Examination of two sections of the coil showed pinhead size pitting cavities at the exterior surface and partially parallel and partially angled array of fine cracks on external as well as the internal surfaces of the bend. Metallographic examination conducted on longitudinal and transverse sections showed predominantly transcrystalline cracks, originated from the pits at the external surfaces of the pipe. Their appearance suggested they were stress corrosion cracks that occur in austenitic steels under the combined effect of stresses and certain corrosion agents, especially chlorides. If chlorides were absent, hydrogen sulfide which causes similar pitting and is capable of causing cracks could be suspected. Favorable state of stresses, which could be residual or due to heat treating, bending or straightening operations, would be recommended for better behavior of the container.

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.

Weld-decay and stress-corrosion cracking developed in several similar all-welded vessels fabricated from austenitic stainless steel. During a periodic examination cracks were revealed at the external surface of one of the vessels. External patch welds had been applied at these and several other corresponding locations. Cracks visible on the external surface developed from the inside in a region close to the toe of the internal fillet weld to the deflector plate, and another deep crack associated with a weld cavity is visible slightly to the right of the main fissure. Microscopic examination revealed that precipitation of carbides at the grain boundaries had taken place in the vicinity of the cracks, but that the paths of the cracks were not wholly intergranular. Conditions present in the vicinity of the internal fillet weld must have been such as to favor both inter- and transgranular cracking. It is probable that the heating associated with the repair welds made from time to time also contributed to the trouble. The transgranular cracks, however, were indicative of stress-corrosion cracking.

An 8 in. diam stainless steel black liquor feed pipe to a carbon steel digester had failed within one year of service. The material was type 316 molybdenum-containing austenitic stainless steel. The service environment was alkaline black liquor at 175 deg C (350 deg F). The pipe had developed cracks on the inside surface coincident with an external support gusset. The cracks initiated at wide corrosion grooves. The early stages were corrosion-assisted fatigue cracks. The cracks initiated at the corrosion grooves and propagated as transgranular SCC with characteristic branching. Evaluation indicated the cracks were localized in an area of high cyclic stresses as a consequence of geometrical constraints on the piping and unsupported cantilever loads. No cracks were found elsewhere in the pipe. In the absence of highly localized service stresses (exceeding yield strength of the material), the corrosion grooving and subsequent SCC would not have occurred in this service environment. The pipe support system was modified with additional gussets to reduce the magnitude of cyclic stresses at the critical areas. The modification was apparently successful.

A cold-formed Grade TP 304 stainless steel swaged region of a reheater tube in service for about 8000 hours cracked because of sulfur-induced stress-corrosion cracking (SCC). Cracking initiated from the external surface and a high sulfur content was detected in the outer diameter and crack deposits. Comparison of the microstructure and hardness of the swaged region and unswaged Grade TP 304 stainless steel tube metal indicated that the swaged section was not annealed to reduce the effects of cold working. The high hardness created during swaging increased the stainless steel's susceptibility to sulfur-induced SCC. Because SCC requires water to be present, cracking most likely occurred during downtime or startups. To prevent future failures, the boiler should be kept dry during downtime to avoid formation of sulfur acids, and the swaged sections of the tubes should be heat treated after swaging to reduce or eliminate strain hardening of the metal.