A detailed fracture mechanics evaluation is the most accurate and reliable prediction of process equipment susceptibility to brittle fracture. This article provides an overview and discussion on brittle fracture. The discussion covers the reasons to evaluate brittle fracture, provides a brief summary of historical failures that were found to be a result of brittle fracture, and describes key components that drive susceptibility to a brittle fracture failure, namely stress, material toughness, and cracklike defect. It also presents industry codes and standards that assess susceptibility to brittle fracture. Additionally, a series of case study examples are presented that demonstrate assessment procedures used to mitigate the risk of brittle fracture in process equipment.

A pressure vessel failed causing an external fire on a nine-story coke gasifier in a refinery power plant. An investigation revealed that the failure began as cracking in the gasifier internals, which led to bulging and stress rupture of the vessel shell, and the escape of hot syngas, setting off the fire. The failure mechanisms include stress relaxation cracking of a large diameter Incoloy 825 tube, stress rupture of a 4.65 in. thick chromium steel shell wall, and the oxidation of chromium steel exposed to hot syngas. The gasifier process and operating conditions that contributed to the high-temperature degradation were also analyzed and are discussed.

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.

A group of control valves that regulate production in a field of sour gas wellheads performed satisfactorily for three years before pits and cracks were detected during an inspection. One of the valves was examined using chemical and microstructural analysis to determine the cause of failure and provide preventive measures. The valve body was made of A216-WCC cast carbon steel. Its inner surface was covered with cracks stemming from surface pits. Investigators concluded that the failure was caused by a combination of hydrogen-induced corrosion cracking and sulfide stress-corrosion cracking. Based on test data and cost, A217-WC9 cast Cr–Mo steel would be a better alloy for the application.

A fire in a storage yard engulfed several propane delivery trucks, causing one of them to explode. A series of elevated-temperature stress-rupture tears developed along the top of the truck-mounted tank as it was heated by the fire. Unstable fracture then occurred suddenly along the length of the tank and around both end caps, following the girth welds that connect them to the center portion of the tank. The remaining contents of the tank were suddenly released, aerosolized, and combusted, creating a powerful boiling liquid expanding vapor explosion (BLEVE). Based on the metallography of the tank pieces, the approximate tank temperature at the onset of explosion was determined. Metallurgical analysis provided additional insights as well as a framework for making tanks less susceptible to this destructive failure mechanism.

A newly installed pipeline leaked during cleaning prior to hydrotest at a pressure of approximately 400 psig. The intended hydrotest pressure was 750 psig. The pipeline was constructed from spiral-welded API 5L-X65 HSLA steel and was intended for seawater injection. Analysis included nondestructive testing, metallography, and scanning electron microscopy. Based on the results, the failure was attributed to transit fatigue, caused during highway transportation. Cracks along the toes of the weld from both the outside and inside surfaces, the transgranular nature of cracking, and the presence of fatigue striations all supported transit fatigue as the damage mechanism.

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.

An investigation was conducted to determine why 16 out of 139 pipe bends cracked during hot induction bending. The pipe conformed to API 5L X65 PSL2 line pipe standards and measured 1016 mm (40 in.) in diam with a wall thickness of 18.5 mm. A metallurgical cross section was removed along a crack on the extrados to document the crack morphology using optical microscopy. In addition to cracking, golden-yellow streaks were visible at the extrados, and the composition was examined using scanning electron microscopy with energy dispersive spectroscopy. Based on the results, investigators concluded the pipe was contaminated with copper at the mill were it was produced.

During the construction of a large-diam pipeline, several girth welds had to be cut out as a result of radiographic interpretation. The pipeline was constructed of 910 mm (36 in.) diam x 13 mm (0.5 in.) wall thickness grade X448 (x65) line pipe. The girth welds were fabricated using standard vertical down stove pipe-welding procedures with E7010 cellulosic electrodes. The crack started partially as a result of incomplete fusion on the pipe side wall, which in turn was a result of misalignment of the two pipes. The crack was typical of hydrogen cracking. Girth welds can be made using cellulosic electrodes. For high-risk girth welds, an increase in preheat and/or a reduction in the local stress by controlling lift height or depositing the hot pass locally before lifting may be required.

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.

Coiled tubing with 80 ksi yield strength manufactured to a maximum hardness of 22 HRC to meet NACE Standard MR0175 requirement for sour gas service failed after being on 38 jobs (70% of its estimated fatigue life). A transverse crack where a leak occurred was identified as the primary failure point. Numerous OD surface fissures were revealed by a low-power microscope. A brittle zone near the OD, identified as a sulfide stress crack with additional fatigue cracking was revealed by SEM. Sulfide stress cracking defined as brittle failure by cracking under the combined action of tensile stress and corrosion in the presence of water and hydrogen sulfide was concluded to have initiated the failure which was propagated by fatigue. It was recommended that in the presence of known corrosive environments the tubing should not be used above 50% of its theoretical fatigue life.

Wet natural gas was dried by being passed through a carbon steel vessel that contained a molecular-sieve drying agent. The drying agent became saturated after several hours in service and was regenerated by a gas that was heated to 290 to 345 deg C in a salt-bath heat exchanger. The tee joint in the piping between the heat exchanger and the sieve bed failed after 12 months. A hole in the tee fitting and a corrosion product on the inner surface of the pitting was revealed by visual examination. Iron sulfide was revealed by chemical analysis of the scale which indicated hydrogen sulfide attack on the carbon steel. The presence of oxygen was indicated by the carbon and sulfur found in the scale on the piping and in the sieves indicated that oxygen combined with moisture produced conditions for attack of hydrogen sulfide on carbon steel. Turbulence with some effect from the coarse grain size was interpreted to have contributed. The piping material was changed from carbon steel to AISI type 316 stainless steel as it is readily weldable and resistant to corrosion by hydrogen sulfide.

A vessel made of ASTM A204, grade C, molybdenum alloy steel and used as a hydrogen reformer was found to have cracked in the weld between the shell and the lower head. Six samples from different sections were investigated. The crack was found to be initiated at the edge of the weld in the coarsegrain portion of the HAZ. The microstructure was found to be severely embrittled and severely gassed in an area around the crack. The microstructure of the metal in the head was revealed to be banded and contained spheroidal carbides. The lower head was established by hardness values and microscopic examination to have been overheated for a sufficiently long time to reduce the tensile strength below the minimum required for the steel. It was interpreted that the wide difference in tensile strength between head and weld metal (including HAZ) formed a metallurgical notch that enhanced the diffusion of hydrogen into the metal in the cracked region. The resultant embrittlement and associated fissuring was established to have caused the failure. The hydrogen was diffused out by wrapping the vessel in asbestos and heating followed by cooling as prescribed by ASME code.

Two leaks were discovered at a sulfur recovery unit in a refinery. The leaks were at pipe-to-elbow welds in a 152 mm (6 in.) (NPS 6) diam line, operating in lean amine service at 50 deg C (120 deg F) and 2.9 MPa (425 psig). Thickness measurements indicated negligible loss of metal, and the leaks were clamped. A year later, 15 additional leaks were discovered, again at pipe-to-elbow welds in lean amine lines. Further nondestructive testing located other cracks, giving a total of 35. These lines had been in service for approximately eight years. Investigation (visual inspection, hardness testing, and micrographic cross-sections) supported the conclusion that the failure was caused by lean amine SCC. It was considered unlikely that these pipe welds had received such a postweld heat treatment, although it is industry practice to postweld stress relieve piping and pressure vessels in lean amine service if the temperature is expected to be above 95 deg C (200 deg F). Recommendations included inspecting all welds using shear wave ultrasonic testing and postweld heat treating all welds in lean amine service.

A case of continual product refinement stimulated by product failures was described. Brittle fracture of gas transmission line pipe steels occurred demonstrating a poor combination of materials, environment, manufacturing and installation problems, and loads. Initial efforts were concentrated towards decreasing the Charpy ductile-to-brittle transition temperature to avoid brittle fracture. It was subsequently revealed that the absorbed energy on the upper shelf of the Charpy energy-temperature curve was critical for arresting a moving crack. Both fracture initiation and fracture propagation were needed be controlled. It was concluded that improved steel processing procedures, chiefly hot-working temperature and deformation control, were also required to optimize microstructure and properties.

A welded natural gas line of 400 mm OD and 9 mm wall thickness made of unalloyed steel with 0.22C had to be removed from service after four months because of a pipe burst. Metallographic examination showed the pipe section located next to the gas entrance was permeated by cracks or blisters almost over its entire perimeter in agreement with the ultrasonic test results. Only the weld seam and a strip on each side of it were crack-free. Based on this investigation, the pipeline was taken out of service and reconstructed. To avoid such failures in the future, two preventative measures may be considered. One is to desulfurize the gas. Based on tests, however, the desulfurization would have to be carried very far to be successful. The second possibility is to dry the gas to such an extent as to prevent condensate, and this corrosion, from forming no matter how low winter temperatures may drop. This measure was ultimately recommended, deemed more effective and cheaper.

Several newly developed liquid propane gas (LPG) cylinders made from Fe-0.13C-0.42Mn steel failed, each fracturing in the longitudinal direction. One of the cylinders was thoroughly analyzed to determine the cause. Deep-drawing flaws were observed on the inner wall of the cylinder, oriented in the direction of the fracture and roughly equal in length. Flaws about 1.3 mm deep, steps, and a chevron pattern were observed on the fractured surface as were cleavage facets, revealed by SEM. Hardness was relatively high and the microstructure near the fracture surface appeared elongated. In addition, the stress intensity factor KI calculated from the value of the internal pressure was lower than that estimated by the fracture toughness test. All of this suggests that the tanks were not sufficiently annealed and prone to brittle fracture. The analysis thus proves that cracks initiated by deep-drawing flaws were the primary cause of failure.

Coiled tubing used in drilling operations failed at the halfway point of its estimated fatigue life. The failure was found to be transverse to the tubing axis. Visual examination revealed a flat fracture surface extending 13 mm with the rest of the fracture showing shear lips indicative of tensile overload. The flat portion of the fracture surface was typical of fatigue cracking. Fatigue striations were revealed by SEM. Corrosion pitting on the tubing ID from which the fatigue crack had propagated were observed on closer examination. The corrosion pitting was speculated to have occurred when the tubing was idle and fluids accumulated at the bottom of the tubing wraps. The coiled tubing was concluded to have failed prematurely due to low-cycle fatigue initiated at corrosion pitting sites. Corrosive attack on the coiled tubing was recommended to be reduced by completely removing fluids or modifying the fluids in the tubing or purging by flowing dry nitrogen to dry it out.

Type 316L stainless steel pipes carrying brine at 120 deg C (250 deg F) and at a pH of about 7, failed by perforation at or near circumferential butt-weld seams. The failure was examined optically and radiographically in the field. Specimens were removed and examined metallographically and with a SEM in the laboratory. The examinations revealed a combination of failure mechanisms. The pitting failure of the welds was attributed to localized attack of an activated surface, in which anodic pits corroded rapidly. Additionally, SCC driven by residual welding stresses occurred in the base metal adjacent to the welds. Use of highly stressed austenitic stainless steels in high-chloride environments having a temperature above 65 deg C (150 deg F) should be discouraged. Solution annealing or shot peening to reduce residual stresses may be advisable. If heat treatment is not feasible after welding, the substitution of a more corrosion-resistant alloy, such as Incoloy 800 or 825, may be necessary.