Bolier Failure 2

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FAILURE ANALYSIS

A background and thorough understanding of materials used in construction, physical and mechanical

properties of materials and their production, fabrication and performance characteristics of the materials, as well

as a working knowledge concerning machinery and structural design, and the application and distribution of

stresses resulting from service loads as they relate to the properties of materials are vital to fully develop as a

successful failure investigator.

In conjunction, a failure analyst must have a procedure; or more precisely, a method for evaluation when a failure

occurs. If a product does not live up to its full life expectancy, there must be an evaluation procedure that willidentify the loss. A method of evaluation that is logical and well planned will enable the analyst to determine the

underlying contributing factors, and provide valid information about the failure for future reference.

Boiler Tube Failures

Determining that a failure indeed occurred is the first step in the method for evaluation. In the case of a boiler

tube, a failure has occurred if the tube develops a leak, breaks into two or more pieces, if it has physical signs of

deterioration that will result in an unsafe environment, or it is incapable of performing its intended function.

Once it has been determined that a failure has indeed occurred, the point of origin must be found, and a

determination must be made as to whether the failure occurred as a result of design, method of manufacturing,

service history and conditions, water chemistry excursions, or from a deficiency in the material. When the point

of origin is located, the investigation may proceed to a study of how the failure occurred, possible causes orfactors in the failure, and possible means of preventative measures.

Why a failure occurs is an important question in the method of evaluation. This question can be approached bybreaking down the failure into mode of failure and cause of failure. Mode of failure is the process by which

the failure occurred. Cause of failure is that which can be fixed or changed to prevent future failures. Each

question provides important clues to the investigation, and although priorities may be quite different, each

question must be addressed and resolved to determine why a failure may have occurred.

Determination of the mode of failure may be a relatively simple process for the failure analyst. However,

identification of the exact cause of the failure is quite difficult, if not impossible, at times. The root cause of a

failure in a complicated investigation may take months to determine, while a simple investigation may take only

an hour depending upon the degree of complexity and the confidence level of the analyst. The investigation mustbe finely tuned; not too narrow and not too broad.

The following survey will present a logical method for failure analysis investigation; which will be applied to the

mechanisms by which boiler tubes fail in service. Actual case histories are provided from the authors many

years of experience.

Failure Analysis Methodology

The failure analyst should question why failure occurred, how to get the equipment back online as quickly as

possible, how to prevent a recurrence, and if more information is needed, how the information can be readily

obtained. With these steps taken a plan of attack can be formed. This is the single most important step in the

method of evaluation. A logical plan for the investigation to follow must be developed and implemented. Eachinvestigation will be different from the last and many variables will make it necessary to make decisions based on

the investigation at hand. If an analyst is hasty in his decisions and does not have a solid plan, the analysis could

be a waste of time. By simply cutting or analyzing a sample carelessly an analyst could destroy his only useful

evidence. The various stages of a successful failure analysis are provided below.

Background information on the make and model of the boiler and the tube, specifications, the service history, and

physical evidence of the failed part are necessary components to determine why, how, when, and where a failure

may have occurred. If these answers are provided during the course of the investigation, future failures may be

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better understood or possibly prevented. Interview all users and operators involved in the failure with point-

related questions. Examples of point-related questions include how was the part treated after failure?, Was it

protected?, How was the fracture handled?, and Did the failure involve overheating, which could have altered

the microstructure of the weld or of the base metal?

The decision to remove a sample specimen is an important part of the failure analysis investigation. Samples

selected should be characteristic of the material and contain a representation of the failure or corrosion attack. For

comparative purposes, a sample should be taken from a sound and normal section. In conjunction, for a complete

metallurgical examination of a failure, samples from the failure, adjacent to the failure, and away from the failure

are necessary.

Proper removal and documentation of the sample, as well as information concerning the equipment, process, and

service conditions are necessary. Important criteria that should be noted when a sample is removed are the date,

equipment number, equipment process name, the manufacturer, heat treatment received, material of construction,

environmental conditions (water treatment, temperature, pressure, and amount of time the equipment is used), and

any abnormal service conditions existing at the time of the failure, or prior to the failure. This background

information will provide the basis for a sound failure investigation.

A preliminary visual examination of the failed part, as well as a non-destructive examination of the failure, with

extensive photographic documentation, precedes any mechanical testing, including hardness and tensile testing, or

any metallurgical examination. The preliminary examination does not change or damage the failed part in any

way.

A macroscopic examination of the surface of the selected specimen begins this stage of analysis, followed by a

microscopic examination. This includes fracture surfaces, secondary cracks, discoloration, abnormalities, originof fracture, and direction of the crack growth. In addition, corrosion product thickness, dimensional analysis, and

level of deposit accumulation (via deposit-weight-density, DWD measurements) can also be evaluated.

Upon completion of the macroscopic and microscopic examination, a metallurgical analysis including etched and

unetched, as well as transverse and longitudinal cross sections is conducted. This form of testing provides

information on microstructural characteristics of the sample in failed and good areas, which allows for

identification of the distinguishing characteristics.

In a fracture failure clues to the mode of failure can be revealed by fractography, while the cause of failure can beidentified through the use of metallurgical and mechanical testing, chemical and surface analysis data. Future

failures may be prevented by fixing or modifying the cause of a failure. This can be demonstrated in the example

of a brittle fracture being the mode of failure. The corresponding cause of the brittle fracture may be temperature,

presence of micro-cracks, or state of stress in the metal. In a failure analysis investigation, each question must be

answered as completely as possible.

A chemical analysis of the metal and corrosion products utilizing x-ray fluorescence spectrometry (XRF),

inductively coupled plasma spectroscopy (ICP), scanning electron microscopy (SEM) coupled with energy

dispersive x-ray spectroscopy (EDS), x-ray diffraction (XRD), Fourier transform infrared spectroscopy (FTIR) for

organic contamination studies, Auger electron spectroscopy (AES) and x-ray photoelectron spectroscopy (XPS)

for surface characterization may follow the metallurgical analysis, depending on the investigation. All of these

techniques are covered in more detail in the reference text by Sibilia5. Information from these different types ofanalyses may provide clues as to the cause of failure.

The analysis of fracture mechanics, including the measurement of fracture toughness and the evaluation of notch

effects, provides information concerning the probability of a catastrophic failure under service conditions.

Accelerated tests, as well as the recreation of the failure through simulated tests, confirm the proposed failure

mechanism.

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Analysis of the evidence and a review of the existing data and documentation are the final stages of failure

investigation. All information is gathered and analyzed to form a determination on the mode and probable cause

of the failure. Identification of the mode and cause of failure provide the source for recommendations for

corrective action. A final report including all relevant data, analyses, and recommendations are compiled and

presented to the client. In litigation investigations, the client may not be interested in the recommendations

section of the report.

ANALYSIS OF INDUSTRIAL FAILURES

Five case histories concerning boiler tube and component failures will be the focus of the following section.The case histories discussed include corrosion fatigue, creep fatigue, O.D. tube erosion, hydrogen damage, and a

major case in life expectancy determination. The approach adopted for each case history will provide the

principal characteristics of the failure, main identifying features, basic problem solving techniques, and applied

aspects of the failures.

Industrial Case 1 Corrosion Fatigue

The client submitted one sample from the eleventh stage feed water heater (FWH) shell of a power stations

number 3 coal fired boiler. The heater shell was specified to be 7/16 inches thick, ASME SA 285 grade C

material (UNS K02801). The shell had been in service for approximately 370,000 hours with service conditions

of 372 F (189 C) and 178 psi (1.23 MPa). We were requested to determine the cause of the through wall

cracking.

The as- received feed water heater shell sample is shown in Figures 1 through 3. A washer had been welded to the

exterior surface of the sample to aid in the removal of the specimen. The weld was coincident with the center ofthe longest visible crack on the exterior surface as shown in Figures 2, 4 and 5. An examination of the interior

surface revealed the presence of numerous other secondary cracks as shown in Figures 6 and 7. All of the

secondary cracks were observed to be parallel to the primary crack.

The sample was cut so that the fracture surfaces of the primary crack could be examined. One of the mating

fracture surfaces is shown in Figure 8. The fracture surface was oxidized. The fracture surface was observed to be

relatively flat and perpendicular to the interior surface of the plate. Adjacent to the interior surface numerous short

perpendicular ridges were found. These ridges represent steps between adjacent independent fracture initiation

locations. The separate cracks then merged to form a single crack propagation front.

A transverse cross section through the cracks in the shell was prepared for subsequent metallographic

examination. In the as polished condition numerous cracks were observed in the shell that had initiated on the

interior surface as shown in Figures 9 through 12. The cracks were relatively straight and perpendicular to the

interior surface which is characteristic of a fatigue mode of failure. The surfaces of the cracks were observed to

possess a gray oxide scale. Etching with a 2% nital solution revealed the existing microstructure which was found

to consist of dark etching pearlite in a mixture of white etching ferrite as shown in Figures 13 and 14. No

evidence of overheating was observed.

The failure of the feed water heater shell was observed to have occurred as a result of corrosion fatigue that had

initiated on the interior surface of the shell. Subsequent EDS analysis of corrosion products indicated no specific

corrosive species such as chlorides.

Industrial Case 2 Creep

A client submitted one cracked finishing superheater tube from a power stations number 1 coal fired boiler.

The tube was specified to be 2 inch (50.8 mm) OD, 0.378 inch (9.60 mm) MWT, ASME SA 213 TP304H

material (UNS S30409). The tube has reportedly been service for about 200,000 hours with service conditions of

1010 F (543 C) and 3500 psi (24.15 MPa). It was also reported that the tube had been subjected to deslagging

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by spraying the outside of the tube with 90 F (32 C) water. We were requested to determine the cause of

failure.

A quantitative chemical analysis was performed on the failed boiler tube and it was determined that the failed

boiler tube did conform to the chemical requirements of ASME SA 213 TP304H austenitic stainless steel.

The finishing superheater tube is shown in Figures 15 and 16. The longitudinal crack in the tube is shown in

Figures 15 and 17. The crack appeared to be approximately 1 inches long. A transverse cross section through

one end of the crack is shown in Figure 18. At least two primary cracks were observed at this location, which

were perpendicular to the tube wall thickness. The tube wall thickness at the location of cracking was measuredto be 0.3626 inch (9.21 mm) which is slightly less than the specified minimum wall thickness of 0.378 inch (9.60

mm). However localized deformation of the tube during the creep rupture process is most likely responsible for

the measured decrease in wall thickness.

One of the mating fracture surfaces was further examined at higher magnification using a scanning electron

microscope. The fracture surface exhibited an intergranular appearance as shown in Figures 19 and 20. The

fracture surface was observed to be highly oxidized.

A transverse cross section through the longitudinal crack in the superheater tube was prepared for subsequent

metallographic examination. In the as polished condition, numerous small cracks were observed within the tube

wall thickness that were parallel and adjacent to the primary cracks as shown in Figures 21 and 22. This pattern

of cracking is characteristic of a high temperature creep mode of failure. Several of the cracks were oxidized asshown in Figure 23 indicating that they were open to an exterior surface. The creep cracks originated primarily at

the inside diameter surface as indicated by the greater number of internal cracks close to the ID surface. See

Figure 24. Adjacent to the outside diameter surface only a few small cracks were observed as shown in Figure25. Internal oxidation plus sulfidation was observed within the tube adjacent to the OD surface as shown in

Figure 26.

Etching with Vilellas reagent revealed the existing microstructures. Carburization was observed adjacent to the

OD tube surface as shown in Figures 27 and 28. Across the tube wall thickness some intergranular plus primarily

intragranular carbide precipitation was observed as shown in Figures 29 and 30. The small internal cracks were

found to have occurred at the grain boundaries as shown in Figures 29 and 30.

The finishing superheater tube was found to have failed in service as a result of creep cracking. Creep is a hightemperature mode of failure that generally produces internal intergranular cracks. There was no indication that

thermal shock contributed to the failure.

Industrial Case 3 O.D. Tube Erosion

A client submitted one perforated left sidewall tube from the power stations number 33 coal fired boiler. The

tube was specified to be 1.75 inch (44.45 mm) OD; 0.200 inch (5.08 mm) MWT; ASME SA 210-A1 material

(UNS K02707). The tube had been in service for approximately 300,000 hours with service conditions of 750 F

(399 C) and 2500 psi (17.25 MPa). We were requested to determine the cause of failure.

A quantitative chemical analysis of the failed tube was performed and it was found that the failed tube did

conform to the specified chemical requirements of ASME SA 210 Grade A-1 plain carbon steel.

The as-received sidewall tube is shown in Figures 31 and 32. The tube contained a single perforated hole as

shown in Figures 33 and 34. Erosion of the outside diameter surface of the tube was observed in the area

surrounding the hole as shown in Figures 34 through 36. Pitting was observed underneath the deposits and

oxidation products on the reverse side of the tube as shown in Figures 37 and 38.

The tube was cut open so that the ID surfaces of the tube could be examined. No corrosion or other deterioration

of the ID tube surfaces were observed. Orange colored flash rust corrosion products were observed around the

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periphery of the hole as shown in Figure 39. A transverse cross section through the tube adjacent to the hole

shows the localized reduction in tube wall thickness at this location as shown in Figure 40. The deterioration of

the tube is occurring solely on the OD surface.

A transverse cross-section through the hole in the tube was prepared for subsequent metallographic examination.

Etching with a 2% nital solution revealed the existing microstructure which was found to consist of dark etching

pearlite in matrix of white etching ferrite. The eroded surface of the tube is shown in Figures 41 and 42.

A transverse cross section through the opposite side of the tube was also prepared for metallographic examination.

In the as polished condition the oxide scale layer on the OD surface is shown in Figure 43. The corrosion pittingof the outside diameter surface of the tube is shown in Figure 44 and was measured to be approximately 0.0114

inch (0.29 mm) deep. Etching with a 2% nital solution revealed the existing microstructure which was found to

consist of dark etching pearlite in a matrix of white etching ferrite as shown in Figure 45. A weld seam was

observed within the failed tube on the reverse side of the tube from the location of failure. See Figure 46.

Therefore the tube does not conform to the specified method of manufacture of ASME SA 210 Standard

Specification for Seamless Medium Carbon Steel Boiler and Superheater Tubes.

A transverse cross-section through the tube was cut and surface ground on one side. Rockwell B scale hardness

measurements were performed and the results are given in the table below. The tube, with measured maximum

Rockwell B hardness of 65.9, conforms to the specified hardness properties for ASME SA 210 grade A-1

material, 79 Rockwell B maximum, as originally manufactured.

The perforated hole in the tube was found to be the result of localized erosion of the outside diameter tube

surface. No erosion or corrosion damage of the inside diameter tube surface was observed. The failed tube was

found to contain a weld seam and so does not conform to the specified method of manufacture for ASME SA 210material. However this does not appear to have any influence on the cause of failure.

Industrial Case 4 Hydrogen Damage

One section of a boiler tube that had experienced corrosion of the inside diameter surface that led to

perforation of the tube wall thickness was analyzed. The sample was identified as number 2 boiler; rear wall tube.

The rear wall tube was reportedly inclined and the corrosion occurred at the 12 oclock position. The tube

material was specified to be 3.00 inch (76.2 mm) OD, 0.250 inch (6.35 mm) MWT, ASME SA 210 material

(UNS K02707). The tube had reportedly been in service for approximately 260,000 hours, or over 29 years, withservice conditions of 750 F (400 C) and 190 psi (13.10 MPa). The tubes were last chemically cleaned in 1995

using the chelant EDTA. We were requested to determine the mechanism of internal corrosion.

A quantitative chemical analysis of the tube material was performed. The tube did meet the specified chemical

requirements of either Grade A-1 (UNS K02707) or Grade C (UNS K03501) of ASME SA 210.

The outside diameter surface of the as received tube section is shown in Figures 47 and 48. All of the visible

surfaces had been surface ground. The inside diameter surface of the as received tube section is shown in Figure

49. A large area of deep corrosion pitting accompanied by thick oxide scale layers at some locations was

observed. Cracking was observed at the bottoms of the deepest corroded areas as shown in Figure 50. White

colored deposits were observed around the periphery of and underneath the thicker black oxide scale layers.

The corrosion products within the corroded area of the inside diameter surface were further analyzed for their

elemental compositions using a scanning electron microscope (SEM) equipped with an energy dispersive x-ray

spectrometer (EDS). A spectrum of the brown deposit covering much of the inside diameter surface is shown in

Figure 51. An EDS spectrum of the thick black scale was obtained and was confirmed to be iron oxide. An EDS

spectrum of the white colored deposit was obtained and was found to contain iron (Fe), phosphorus (P), oxygen

(O), carbon (C), aluminum (Al), silicon (Si), copper (Cu), and zinc (Zn) plus lesser amounts of sulfur (S), calcium

(Ca), and manganese (Mn).

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A transverse cross section through the secondary crack in the tube was prepared for subsequent metallographic

examination. In the as polished condition, the scale deposit on the inside diameter (ID) surface of the tube, in a

non corroded area is shown in Figure 52. The scale layer contained a considerable number of metallic copper

particles. At locations where the tube wall thickness exhibited reduced values due to corrosion, cracking and

void formation was observed adjacent to the ID surface that extended almost all of the way across the tube wall

thickness. See Figure 53. Etching with a 2% nital solution revealed the existing microstructure which consisted

of dark etching islands of pearlite in a matrix of white etching ferrite as shown in Figure 54. The microstructure

within the damaged area is shown in Figure 55. The tube wall thickness at the secondary crack was measured to

be 0.116 inch (2.95 mm). The tube wall thickness away from the corrosion pitted area was measured to be 0.214

inch (5.44 mm).

The tube failed as a result of hydrogen damage which had initiated in a portion of the tube that had experienced a

considerable decrease in wall thickness due to corrosion of the inside diameter surface. The corrosion, in turn,

may have been caused by a localized acidic corrosion cell.

Industrial Case 5 Life Expectancy Determination

Boiler tubes in a clients No. 1 unit were exposed to overheating for a total of 94 hours over a period of two

weeks. The tubes were ASME SA 213-T2 (UNS K11547) with minimum properties of 60 psi (4.14 MPa) tensile

strength, 30 psi (2.07 MPa) yield strength, and 30 percent elongation. The client requested an independent

evaluation of the effect of the exposure of the tubes to high temperature and the resulting changes in their life

expectancy. The overheating resulted from faulty tube connections which restricted the cooling circulation tonear zero in the second pass Installation of jumper tubes subsequently corrected the problem. The overheating

resulted in one tube failure after 14 hours of overheating, a second tube failure after 36 hours of overheating, and

a third tube failure after 43 hours of overheating. Tubes under internal pressure operating at elevated temperaturefor extended periods of time can eventually split longitudinally due to creep tensile instability.

The first and second boiler pass circuit design temperature was 750 F (399 C) and the design pressure was 4,300

4,450 psi (296.5 306.8 MPa). The measured hourly second pass boiler tube temperature was 725 F (385 C)

and the maximum average temperature was 732 F (389C). Of course, individual tubes with no flow would

experience higher temperatures. The maximum hourly primary superheater outlet pressure was 3,832 psi (264.2

MPa) and the maximum measured pressure at any time was 4,096 psi (282.4 MPa). .

A quantitative analysis was performed of the creep rupture damage which the remaining uncracked tubesexperienced while pressurized at elevated temperature for 04 hours, and the effect of the this damage on the

remaining life of the tubes was determined. The analysis was performed to quantify the percent creep rupture

damage experienced by the first and second pass tubes during the 94 hours of elevated temperature operation.

The evaluation is carried out using the minimum elevated temperature creep and creep rupture properties of the

material, an accepted practice in such evaluations. The temperature at which creep tensile instability rupture

occurs under the known operating pressure can be evaluated for various times of high temperature exposure. The

evaluation is accomplished using the known solution for creep tensile instability in a pressurized tube and the

isochronous stress-strain properties of the tube material.

The solution for creep tensile instability in a thin-walled tube follows the classical Considere solution for plastic

tensile instability.6 The application of this solution using the properties of the tube material provides the

maximum average temperature during the 94-hour period of elevated temperature operation for the tubes whichdid not fail. The minimum isochronous properties for the tubing material for temperatures ranging between 750

F (400 C) and 1,200 F (649 C) were estimated from isochronous curves provided in the ASME Code for

Components in Elevated Temperature Service.7 An examination of the isochronous stress-strain properties for 94

hours of operation using the solution of for creep tensile instability shows that the temperature did not exceed

1,050 F (566C). Thus, the tubes which did not fail and which had the minimum strength properties were

exposed to no more than 1,050 F (566 C) for 94 hours. At 1050 F (566 C), the maximum allowable stress for

31 hours at a design margin of 1.5 is 12,260 psi (845.3 MPa). This design life failure is intended to cover scatter

in the material properties and is quite consistent with single tube failures at 14, 36, and 43 hours respectively.

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In order to conservatively quantify the creep rupture damage experienced during 94 hours at 12,260 psi (845.3

MPa), it is necessary to use the elevated temperature material properties. Based on these properties, creep rupture

is calculated to occur after 1,196 hours of operation at 12,260 psi (845/3 MPa) for material having the minimum

expected creep rupture strength. The corresponding creep rupture damage for 94 hours of operation at 1,050 F

(566 C) is 96 hours divided by 1,196 hours, or approximately 8 percent. Based on the tube design temperature

and pressure, the hoop stress in the tubes under design conditions is 13,314 psi (918.0 MPa). The allowable stress

for such tubes designed to Section I of the ASME code8,9 is 15,400 psi (1,061.8 MPa). Thus, the design of the

tubes meets the code allowables. At the design temperature of 750 F (400 C), the allowable stress is not

governed by the time-dependent properties. This means that the 8 percent creep rupture damage will not shortenthe life by 8 percent for operation at the design temperature.

The significance of the 8 percent creep rupture damage which occurred in only 94 hours at 1,050 F (566 C) is

that 8 percent of the creep rupture life of the tubes was expended during this period. Thus, the tube tolerance for

other abnormal elevated temperature excursions was reduced by 8 percent. The tubes are therefore fit for

continued service. Only a very small percentage of tubes would be expected to have creep rupture properties

below the minimum expected values given in the ASME Code. Such tubes may fail with less than 100 percent of

the creep rupture damage calculated using the minimum properties. Should the tubes be exposed to abnormally

high temperatures such that they reach an accumulated 100 percent creep rupture damage condition(based on

minimum expected properties) due to all temperature excursions, they would not be fit for continued service and

should be replaced.

CONCLUSION

This paper emphasized the basic problems and applied aspects of the corrosion and metallurgical failures ofboiler tubes. Four separate types of failures were presented detailing the factors and mechanisms affecting the

failures, as well as a case in life expectancy determination. Corrosion fatigue results in initiation and propagation

of cracks. Creep can lead to the formation of internal intergranular cracks. O.D. erosion can lead to tube wall

perforation. In another case the boiler tube failed as a result of hydrogen damage which had initiated in a portion

of the tube that had experienced a considerable decrease in wall thickness due to corrosion of the inside diameter

surface. Remaining life assessment requires quantification of creep rupture damage and consideration of

allowable stress for the tubes.

REFERENCES

1. M. Zamanzadeh, E.S. Larkin, G.T. Bayer, and W.J. Linhart, Failure Analysis and Investigation Methods forBoiler tube Failures. NACE Corrosion 2007, Paper 7450, Nashville, TN, March 2007.

2. D.N. French, Metallurgical Failures in Fossil Fired Boilers, Second Edition, New York, NY: John Wiley &Sons, Inc., 1993.

3. R.D. Port and H.M. Herro, The NALCO Guide to Boiler Failure Analysis, New York, NY: McGraw-Hill,Inc., 1991.

4. C.R. Brooks and A. Choudhury, Failure Analysis of Engineering Materials, New York, NY: McGraw-Hill

Companies, Inc., 2002.

5. J.P. Sibilia, A Guide to Materials Characterization and Chemical Analysis, Second Edition, New York, NY:

Wiley-VCH, Inc., 1996.

6. W.J. ODonnell and J.S. Porowski, Creep Tensile Instability. Journal of the Institution of MechanicalEngineers, 1980, pp. 33-42.

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7. ASME Boiler and Pressure Vessel Code, Section III, Subsection NH, Class 1 Components in ElevatedTemperature Service, 1995 Edition.

8. ASME Boiler and Pressure Vessel Code, Section II, Materials, Part D, Properties, 1999 Addenda.9. ASME Boiler and Pressure Vessel Code, Section I, Rules for Construction of Power Boilers, 1999 Addenda.

.

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FIGURE 1 - Photograph showing the as received feedwater heater shell sample.

FIGURE 2 - Photograph showing the exterior surface of the as received feedwater heater shell sample.

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FIGURE 3 - Photograph showing the interior surface of the as received feedwater heater shell sample.

FIGURE 4 - Photograph showing the weld overlapping the primary crack on the exterior surface.

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FIGURE 5 - Photograph showing the weld overlapping the primary crack on the exterior surface.

FIGURE 6 - Photograph at 8x showing secondary cracking in the interior surface.

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FIGURE 9 - Photograph at 50x showing the secondary cracks at the interior surface of the shell; as

polished.


polished

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polished


polished

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FIGURE 13 - Photograph at 50x showing the microstructure of the shell; 2% nital.

FIGURE 14 - Photograph at 400x showing the microstructure of the shell. 2% natal.

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FIGURE 15 - Photograph showing the longitudinal crack in the as received superheater tube.

FIGURE 16 - Photograph showing the opposite side of the superheater tube.

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FIGURE 17 - Photograph at 5.5x showing the longitudinal crack in the as received superheater tube.

FIGURE 18 - Photograph at 2.3x showing the cracking in the superheater tube.

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FIGURE 19 SEM micrograph 75x showing the fracture surface.

FIGURE 20 SEM micrograph at 75x showing the fracture surface.

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FIGURE 21 - Photograph at 100x showing cracking and creep void formation at the ID tube surface; as

polished

FIGURE 22 - Photograph at 100x showing cracking and creep void formation; as polished

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FIGURE 23 - Photograph at 400x showing creep void formation near the ID tube surface; as polished.

FIGURE 24 - Photograph at 100x showing creep void formation near the ID tube surface; as polished.

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FIGURE 25 - Photograph at 100x showing the oxide scale layer plus shallow cracking at the OD tube

surface; as polished.

FIGURE 26 - Photograph at 1000x showing internal oxidation plus sulfidation at the OD tube surface; as

polished.

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FIGURE 29 - Photograph at 400x showing the microstructure of the tube near the ID surface; Vilellas

reagent.

FIGURE 30 - Photograph at 1000x showing the microstructure of the tube near the ID surface; Vilellas

reagent.

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FIGURE 31 - Photograph showing the as received sidewall tube sample.

FIGURE 32 - Photograph showing the as received sidewall tube sample.

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FIGURE 33 - Photograph showing the perforated hole in the tube.

FIGURE 34 - Photograph at 8x showing the perforated hole in the tube.

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FIGURE 35 - Photograph at 8x showing erosion of the OD tube surface.

FIGURE 36 - Photograph at 8x showing erosion of the OD tube surface.

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FIGURE 37 - Photograph at 8x showing pitting of the reverse side of the tube.

FIGURE 38 - Photograph at 8x showing pitting of the reverse side of the tube.

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FIGURE 39 - Photograph showing the hole and ID surface.

FIGURE 40 - Photograph showing the wall thickness profile adjacent to the hole.

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FIGURE 41 - Photograph at 100x showing the eroded profile of the OD tube surface;

2% nital.

FIGURE 42 - Photograph at 200x showing the eroded profile of the OD tube surface;

2% nital.

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FIGURE 43 - Photograph at 100x showing the oxide scale layer on the reverse side of the tube; as polished.

FIGURE 44 - Photograph at 50x showing the corrosion pitting of the OD surface on the reverse side of the

tube; as polished.

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FIGURE 45 - Photograph at 400x showing the microstructure of the tube on the reverse side of the tube;

2% nital.

FIGURE 46 - Photograph at 100x showing the weld seam in the failed tube; 2% nital.

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FIGURE 47 - Photograph showing the OD surface of the as received tube section.

FIGURE 48 - Photograph showing the perforation in the tube wall thickness at the OD surface.

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FIGURE 51 - EDS spectrum of the brown colored ID deposit.

FIGURE 52 - Photograph at 200x showing the ID oxide scale layer; as polished.

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FIGURE 53 - Photograph at 50x showing cracking and hydrogen damage void formation; as polished.

FIGURE 54 - Photograph at 1000x showing the microstructure of the tube; 2% nital.

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FIGURE 55 - Photograph at 1000x showing the microstructure of the tube in the hydrogen damaged area;

2% nital.

Bolier Failure 2

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