Rst-164 Condition Assessment of Boiler Piping & Header Components

8/21/2019 Rst-164 Condition Assessment of Boiler Piping & Header Components

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Babcock Borsig Power, Inc.Post Office Box 15040

Worcester, MA 01615-0040www.bbpwr.com

TECHNICAL PUBLICATION

RST-164

CONDITION ASSESSMENT

OF BOILER PIPING

AND HEADER COMPONENTS

byJames P. King

Senior Staff EngineerBabcock Borsig Power, Inc.

Presented at the2000 ASME Pressure Vessels and Piping Conference

Seattle, WashingtonJuly 23-27, 2000

Babcock Borsig Power Inc. is nowBabcock Power Services Inc., a Babcock Power Inc. company.

www.babcockpower.com


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© Babcock Borsig Power, Inc. 2001

CONDITION ASSESSMENT OF BOILER PIPING

AND HEADER COMPONENTS

byJames P. King

Senior Staff EngineerBabcock Borsig Power, Inc.

ABSTRACT

This paper provides current and cumulative experience with typical problems and fail-ures associated with fossil fired utility boiler pressure piping and header components. Thebackground for the paper is the experience of DB Riley (now Babcock Borsig Power, Inc.) inboiler inspections, testing, metallurgy and remnant life studies, performed on their own andunits designed by other original equipment manufacturers during the past fifteen years.

Case studies are presented which address the significance of cyclic boiler operation andover-temperature conditions on header and piping components. The studies include theassessment of cracking in high temperature superheater outlet headers, the evaluation of a

sagged reheat inlet header, and a study of a test spool piece taken from a hot reheat piping line.

The summary includes a table listing common problems with boiler piping and headercomponents including the description of damage, failure cause, inspection and nondestruc-tive, and metallurgical testing tasks, with recommended remedial actions for each of themajor pressure components.

INTRODUCTION AND BACKGROUND

The performance of condition assessment, or life extension, programs has been an inte-gral and ongoing activity for fossil fired utility boilers during the past eighteen years. Theseprograms were implemented, in part, due to a history of catastrophic component failures, theaging of the equipment and to the cyclic or load following type of operation utilized for mostunits. Historically, electric utilities scheduled unit outages on an annual or eighteen-monthcycle. Today, the interval of time between outages has been extended to as much as thirty-six months. This pattern of scheduling less frequent outages requires better record keeping and more detailed planning for the inspection, assessment, and maintenance tasks per-formed during the outage.

Initially, the focus of a condition assessment program was on the major boiler pressureand steam line components. However, over the years, the programs have been extended to


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include the structure and setting of the boiler and the many regions of water wall, econo-mizer, superheater, and reheater tubing. Also, the boiler proper downcomer and crossoverpiping, including branch lines and steam attemperator components are now a part of suchprograms. In recent times, there has been much more attention given to the feedwater pip-ing line components due to a number of reported failures which were attributed to flow accel-erated corrosion. In addition, sloped horizontal steam piping lines should be evaluated for

the effects of water induction, especially if there is visual evidence of sagging or distortion.

In today’s age of deregulation in the electric power industry, with many changes in plantownership, it is now more important than ever to have a continuing boiler condition assess-ment program in place. This provides easy availability of records, via previous detailedreports with implemented recommendations, and a schedule of inspection, testing, and mon-itoring activities for future unit outages. Most importantly, a continuing condition assess-ment program helps to ensure safe and reliable operation of the units, and minimizes thefrequency of forced outages.

CURRENT EXPERIENCE

Babcock Borsig Power, Inc. (BBP) continues to be involved with condition assessmentand failure analysis studies of fossil fired boiler components. The aging of the utility boilerfleet and the cycling and load swing modes of operation employed over the years has neces-sitated the periodic performance of condition assessment programs and the occasional fail-ure analysis study.

It has been our experience that many of the boiler operational problems, with accumu-lation of fatigue damage, occur during the early years of unit service when events such asturbine, boiler, and/or mill trips are most likely to happen.

Four case studies of recent failure or distress in critical boiler and piping pressure com-ponents are described in detail below.

CASES 1 AND 2: CRACKING IN HIGH TEMPERATURESUPERHEATER OUTLET HEADERS

BBP has been involved, with others, in two separate studies addressing cracking foundin regions of high temperature superheater outlet headers.

Case No. 1

This study was for a 1972 design, large utility boiler originally supplied by Riley StokerCorporation, described in the Reference 1 report. Circumferential cracking was found at onegirth weld location between the header shell and an outlet block forged tee. By ultrasonictesting, the cracking was found to be through wall for the upper 180° portion and with lessdepth for another 45° on either side.

The history of boiler duty, as related by plant personnel, included a period in the early tomid-1980’s with continuous load swing operation, including some times at loads as low as10% of maximum. During low load operation, superheater temperatures can vary signifi-cantly from pendant to pendant and from tube to tube. The many cycles associated withdaily load swing operation can cause cumulative fatigue damage. Historically, the super-heater has experienced higher temperatures towards the middle of the boiler, which was thelocation of the cracked weld in the outlet header.


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The repair program involved the removal of weld metal by thermal gouging and grind-ing, with confirmation of crack removal by magnetic particle examination.

Upon initial visual examination, it appeared that the thin, discontinuous circumferentialcracks had initiated on the outside surface of the header weld; however, during the repairprocess, it became evident that the cracks were wider towards the inside surface, thus indi-

cating crack initiation at the inside surface.The metallurgical results of boat samples, taken prior to the repairs, showed transgran-

ular cracking indicative of fatigue, with minor evidence of non-aligned creep voids.This indi-cates that fatigue was the primary failure mode, with some minor interaction from creep.The greatest accumulation of fatigue damage would be during the period of cyclic operation

Extensive ultrasonic shear wave testing was performed on all similar locations of theheader with some minor subsurface indications found, which were recommended for moni-toring.

At a moment restraint assembly near the cracked girth weld, some minor indicationswere found in attachment welds, and some plate members were slightly twisted. This couldbe indicative of some higher than anticipated external loading, from the outlet main steam

piping.

In conclusion, the appropriate testing and repair procedures were utilized by the owner,and recommendations were given for continued monitoring, determining the causes of high-er temperatures at the middle of the superheater and for the minimizing of cyclic and loadswing operation.

Case No. 2

This case involves a 1976 design large utility boiler, as described in the Reference 2report. Circumferential cracking was found in the ligament fields, at many locations on twin,high temperature superheater outlet headers, of this boiler. At the most severe locations,through wall cracking was observed from tube hole to tube hole circumferentially. These

locations were at the outboard end of each header. See the Figure 1 photograph for a gener-al view of the header. Historically, the superheater had recorded higher temperatures at

Figure 1 General view of the Case No. 2 H.T. superheater outlet header,showing where the terminal tubes were cut away for later replacement.


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these same ends. Also, the unit had been operated in a load swing mode during a number of its years in service. Due to the orientation of the cracking, it was obvious that the combina-tion of the longitudinal thermal bending and pressure stresses is greater than the value of the circumferential (hoop) pressure stress.

A comprehensive ultrasonic testing program was performed for each of the ligament

fields on both headers. A map of crack locations and depths was generated for each header.Boat samples were taken for metallurgical analysis from the circumferential ligament fields.See the Figures 2 and 3 photographs. The results of this analysis showed the cracking to beprimarily due to thermal fatigue.

Figure 2 Area of the header where a boat sample was removed from thecircumferential ligament field for metallurgical analysis

Figure 3 A closeup view of the top of the header, showing a location ofremoved terminal tubes, with the wide circumferential cracks


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Due to the extent and severity of the cracking, replacement spool pieces were obtained,machined and installed at the outboard ends of the headers before the unit was placed backinto service.A longer-term plan was initiated for complete replacement of both headers. Thenew headers would have some redesigned features, including the use of SA-335 P91 mater-ial, rounding of all internal sharp edges especially at bore holes, increasing the circumfer-ential tube spacing, and designing a more flexible inlet tube routing in the penthouse. P91

material has increased creep rupture strength and allowable stress values, which providesfor a thinner header and thus making it less susceptible to fatigue damage. Also, the needfor more evenly distributed temperatures is being evaluated by changes to the upstreamsteam circuitry.

Once the header piece replacement program was established, the owner authorized afailure study to determine the root cause of the cracking. Part of the study utilized sectionsand specimens taken from a removed piece of header. As a conclusion of the failure study, wedetermined that a major contributor to the cracking was the presence of a normal operating (100°F) cross-sectional thermal gradient from the top to bottom of the header, which has agreater value (up to 200°F) during start-up events. These temperature gradient values wereconfirmed by a review of operational charts.A similar cracking (failure) scenario is described

in detail in the Reference 3 technical paper for the high temperature superheater outletheader on a large utility boiler.

Case No. 3 - Sagged Reheat Inlet Header

Recently, BBP performed a complete condition assessment program for a sagged reheatinlet header, located in a utility steam generating unit firing pulverized coal. See theReference 4 report. The unit has a maximum continuous rating of three million pounds of steam per hour. The header was originally specified as 26 inch outside diameter by 1.25 inch-es minimum wall, SA 106 Grade C material.

According to the our field service files, the unit was first placed into service in 1972, andsome sagging of the header was first discovered as early as 1974. A testing program was per-

formed by the owner, BBP, and the pipe support manufacturer in 1979. The testing tasksincluded outside diameter and vertical deflection measurements, ultrasonic wall thicknessmeasurements and metallurgical analysis of header wall plug samples.

Only the metallurgical results were available in our files and they showed normalmicrostructure with no evidence of spheroidization for the plug, header wall samples.Information from the files indicated that the following additional future tasks were to beimplemented.

• Performance of a complete stress analysis of the cold reheat piping from the tur-bine to the header including the reheat inlet header.

• “Break” the flange welds connecting the header to inlet piping on each end and

check for relative movements and spring.It is not known if these tasks were performed. Also, there is no historical information in

the files about any further inspections and testing of the header and piping componentsbetween 1979 and the late 1990’s.

The recent condition assessment program was initiated by the owner due to concernsthat the header sagging condition might have worsened. In the program, components of thereheat inlet header and the cold reheat inlet piping and their supports were evaluated. Theprogram tasks included visual and internal video inspections, header outside diameter and


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offset (sagging) measurements, ultrasonic thickness and magnetic particle testing, and sur-face replication and hardness testing.

The results of this current comprehensive inspection and testing program indicatedsome problem areas. Obviously, the header sagging was of concern. This condition had beenknown for a long time, but a visual inspection and measurements showed it had not wors-

ened significantly. The sagging of the header, measured from a taut line, was found to rangefrom 7 to 9 inches at the lowest location over the 60 foot long header, an increase of one totwo inches over a twenty-year period. See the Figures 4 and 5 photographs.

Figure 4 The Case No. 3 reheat inlet header, located in theconvection pass of the boiler, showing obvious sagging

Figure 5 A view of a deformed support bracket at thereheat inlet penetration of the left convection pass wall


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Figure 6 General view of the cold reheatpiping near its inlet to the boiler.

The result of the current outside diameter measurements, ultrasonic thickness readings,magnetic particle testing and internal video inspection for the header showed no seriousproblems.

Surface replication was performed at two locations on the header. The 1997 microstruc-tural results showed no evidence of creep voids. The results did show the presence of in-situ

spheroidization, opposed to the 1979 normal results, which would indicate normal degrada-tion for a carbon steel component experiencing temperatures in the vicinity of 850°F for along period of time. However, the design temperature for the reheat inlet header is 700°F,therefore the component has experienced higher than expected temperatures, either during long-term operation or during a series of short term events.

The degree of spheroidization was judged to be Stage 3, as defined in the Reference 5 doc-ument, which is based on the Reference 6, Toft and Marsden technical paper. The estimateof 850°F temperature exposure is based on BBP’s extensive experience.

The over-temperature condition is also confirmed by the hardness testing results, whichshow some loss of material tensile strength at the header surface locations. Simplifiedremaining life calculations were performed as a further means of verifying the microstruc-

tural conditions. Cases were input for temperature values of 800°F and 850°F for the life of the header. Average Larson-Miller parameter values for stress rupture strength from theReference 5 document were input. The results showed infinite service life at 800°F and100,000 hours remaining life at 850°F.

The physical walkdown and visual inspections of the cold reheat piping and supportsrevealed some problem areas. See the photographs in Figures 6, 7, and 8. The most signifi-cant of these items is the evidence of some damaged and deformed support structural mem-

Figure 7 First support off right handside of boiler. Note that both structural

channels are bent and dented.


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bers and dented pipe lagging, especially at the first and second support locations from thereheat inlet connections on both sides of the boiler. This type of damage is most likely aresult of excessive loadings and movements experienced by the piping line componentsdue to abnormal or non-specified plant or system events. The cold settings for the constantforce supports showed normal travel indications. There was no hot walk-down performedfor this study.

Based on the review of records and the results of the many inspections, tests, and met-allurgical tasks performed on the header, and the visual observations from the piping inspec-tion, there is no obvious reason for the original and subsequent sagging of the header. Themost likely scenario is the occurrence of higher than designed loads imposed on the headerby the cold reheat inlet piping system, as evidenced by the damaged and deformed piping support structural members adjacent to and at the boiler-to-piping interface. In addition, thediscovery of some minor to moderate overheating by the metallographic replica results takenon the header surface has raised concern with the source of the overheating, and with anypossible future consequences.

Based on the findings and conclusions from the condition assessment program, the fol-lowing recommendations were given to the owner in a detailed final report:

Institute a monitoring program for the reheat inlet header components. At a min-imum during each major boiler outage, a complete visual inspection should beperformed, and diameter and sagging measurements taken. Also, replicationwith hardness testing should be performed to provide the current condition.These results should be compared with previous results for evidence of any fur-ther deterioration.

• In the short term, it is recommended that header core samples be taken formicrostructural evaluation of “original” material, through the wall, with tensileand stress rupture testing.

Figure 8 Constant force support on the cold reheat piping. Note the deformed structuralchannels. Also, additional channels appear to have been added for stiffening; however,

they have been attached to the spring can cover, which is poor practice.


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• Investigate the source of the higher-than-design temperatures experienced by theheader. This could involve the installation of thermocouples to the header, and anextensive review of applicable boiler temperature records. A part of this reviewshould include the frequency and duration of attemperation, via the two-reheatinlet spray stations.

• Have a stress analysis program performed for the complete cold reheat piping system, including the header. Input as much current information as possibleincluding the condition of the supports. Computer cases should be run to repre-sent normal loadings such as pressure, deadweight, thermal expansion, and coldspring. Also include supplemental cases to represent any abnormal or additionalloadings such as those from over-temperature conditions, and valve thrust or

valve closure, from events such as a turbine trip. The resulting forces, moments,and stresses from these load cases can be evaluated to the applicable ASME codeequations, and applied to the piping supports to determine adequacy. The exter-nal loadings on the reheat inlet header can also be evaluated for conformance. Inaddition, the resulting moment values could also be used as inputs to a fatigueevaluation of header and piping components.

• In conjunction with the stress analysis program described above, a recommenda-tion is given to proof test the first two constant force support assemblies on eachside of the boiler. The results of this test, which can be done on site, will determineif the supports are still capable of carrying the loadings for which this 1972 boil-er was originally designed.

• As a maintenance-monitoring item, perform scheduled internal video inspectionsof the inlet reheat spray station components to assure that the components are inplace and the spray nozzles and associated branch connection welds are adequate.

Case No. 4 - Hot Reheat Piping Spool Piece Testing

During an on-site scheduled condition assessment program for hot reheat steam piping lines, indications were identified by ultrasonic shear wave testing and surface creep damagewas observed by metallographic replication in the longitudinal seam weld and girth weldsin portions of the piping. See Reference No. 7. In order to more closely examine and definethese indications, and to provide an assessment of the current condition of the piping andweldment materials, a three-foot long piece of the pipe was removed for a comprehensiveanalytical and testing program. This spool piece was cut out eighteen inches on each side of a circumferential weld and contained two offset portions of long seam weld. See the Figure9 photograph.

The subject hot reheat piping is part of a TURBO® Furnace unit with a net output of 580megawatts. The boiler burns low sulfur western coal and was designed to operate at 2620psig, 1005°/1005°F, with a steam flow capacity of 4.3 million pounds of steam per hour. The

unit began commercial operation in 1980 and at the time of spool piece removal, had loggedapproximately 106,000 hours of service with over 220 starts. The boiler was originallydesigned to be base loaded; however, as with many such units, it is subjected to typical dailyload cycling from 35 to 100 percent of full load capacity.

Records for the first two years of operation reveal that the boiler experienced an exces-sive number of mill trips with associated boiler trips, and also severe steam temperaturecontrol problems. Outlet steam temperatures ran as much as 200°F above design values. Theinstallation of additional steam attemperation, along with control system modifications,


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improved the temperature control considerably, whereby; the main and reheat steam lineoutlet temperatures could be operated at their design values.

The hot reheat piping was originally fabricated from rolled and welded plate stock. Thematerial is ASTM A155-Class 2-1/4 alloy steel plate, which is joined with a longitudinalseam weld. The finished pipe has a nominal wall thickness of 1.124 inches. The piping has a

design temperature of 1015°F and a maximum operating pressure of 600 psig.

Figure 9 The Case No. 4 as-received test spool piece of the hot reheat piping,showing the girth weld and a portion of the longitudinal seam weld.

This in-depth analytical and testing program consisted of the following tasks:

• Visual Inspection and Nondestructive Testing · Visual Inspection· Wet Fluorescent Magnetic Particle Testing · Radiographic Testing · Ultrasonic Testing

• Physical and Chemical Evaluation· Optical Metallography· Scanning Electron Microscopy· Spectrochemical Analysis· Hardness Testing

• Mechanical Testing · Stress-Rupture Testing

· Elevated Temperature (J) Fracture Toughness Testing · Creep-Crack-Growth (C*) Testing · Remaining Creep Life Assessment

For the stress-rupture testing, two blanks oriented across the downstream leg of longi-tudinal weld were machined into tensile specimens with a 1/4 inch diameter by 2 inch long gage section. The specimens were located so that the welds and heat-affected zones were inthe gage section. The specimens were loaded in tension in standard creep test frames andheated in air using a standard laboratory test furnace. The tests were accelerated by using


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1225° and 1250°F temperatures, which are well above the maximum service temperature,with a stress value of 7,000 psi. This stress value was chosen so that the results could becompared directly with those of a past study conducted for the Electric Power ResearchInstitute. See Reference 8.

Based on the findings of the analyses and testing of the spool piece, which were con-

ducted according to current industry guidelines (Reference 9) for detecting damage in theweldments of high energy steam piping, the following conclusions were made for this com-ponent

• Visual inspection yielded no evidence of gross defects in the spool piece. Unlikethe inherent limitations of in-situ inspection of piping, laboratory analysis offeredthe obvious advantage of examining the internal surface of the spool piece, by

visual, nondestructive and destructive techniques. The Figure 10 photographshows a macroetched end view of the spool piece including the longitudinal weldprofile. The most significant finding was the presence of a non-uniform counter-bore at the l.D. of the girth weld. This discontinuity was introduced during theoriginal joint preparation of the pipe ends prior to welding. This was initiallyidentified as a crack indication both by ultrasonic testing (UT) and radiography

(RT), since the internal surface of the pipe could not be seen in the field.

Figure 10 The macroetched, cut end of the spool piece,showing the asymmetry of the double-V seam weld.

• Indications were detected in the girth weld by both UT and RT. In the laboratory,the largest indication was identified as a fabrication induced flaw, namely lack of root fusion, by metallographic examination. No evidence of creep damage wasfound to be associated with the flaw, when examined by optical microscopy.

• No evidence of creep damage was observed in the metallographically preparedspecimens of the long seam or girth welds. The piping base metal showed only

beginning stage spheroidization indicating that service temperatures had notseriously degraded the metal.

• A significant concentration of nonmetallic inclusions was observed in the weldmetal of the upstream longitudinal weld, particularly evident along the fusionline in the cusp region of the weld. Chemical analysis of the weld material showedthat the oxygen content is consistent with the use of an acid type flux during orig-inal fabrication. These inclusions are typical of those found in welds made by thesubmerged-arc welding process. One study (Reference 10) suggests that high con-


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centrations of nonmetallic inclusions near the fusion line of long seam welds, asintroduced by the welding process and acid type fluxes, may increase the likeli-hood for creep damage to initiate. Contrary to the observation of a high concen-tration of weld metal inclusions, the results of the cross-weld stress-rupture testsindicate that the stress-rupture life of the longitudinal seam weld has not beenseriously degraded by their presence or by service conditions.

• Remaining creep life assessment was done using the results of the stress-rupturehigh temperature (J) toughness, and creep-crack-growth testing carried out onspecimen of the long seam weldment. The findings indicate that service tempera-tures and pressures have not significantly reduced the creep properties of the pip-ing weldment, and furthermore, that the test results of the weldments are com-parable to industry findings for 2-1/4CR-1Mo base metal. Specifically, (1) the min-imum creep rupture strength is represented by the lower bound of creep rupturestrength for new 2-1/4Cr-1Mo steel, (2) the secondary creep rate (pre-cavitationstage) is represented by the typical behavior of service exposed 2-1/4Cr-1 Mosteel, and (3) the maximum creep-crack-growth rate is represented by the upperbound of 2-1/4Cr-1Mo base metal.

• Remaining creep life was estimated using: (1) a simplified model based on thestress-rupture test results, and (2) a more conservative model in which a flaw hasbeen introduced to the weldment via a machined notch and fatigue pre-cracking.In the first approach, a total remaining life of 3,811,000 hours was calculatedusing the linear life-fraction rule. In the second, the predicted remaining creeplives, using the creep-crack-growth model and typical operating parameters weremore conservative, a total remaining life of 721,000 hours is predicted.

• The creep-crack-growth model shows that the average operating pressure of 509psig and temperature of 1001°F for this steam piping are reasonable based on theparameters of the specimens tested and operational data reported.The specimensprior to testing are shown in Figure 11.Adequate remaining life is expected understeady-state conditions and in the absence of material flaws or sustained, undueoperational loading.

• A calibration block has subsequently been fabricated from the spool piece forfuture ultrasonic examination of the unit’s steam piping.

Figure 11 The stress rupture and creep-crack-growth specimens taken from the test spool piece.


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SUMMARY

Recent experience in problem areas encountered with critical boiler header and piping components has been described for cracking or distress found in such pressure retaining components. These problems are a result of today’s operational practices, including cyclicduty and extended life for older boilers, which have accelerated the propensity for crack ini-

tiation and eventual failure of components.For the two studies involving cracking in regions of high temperature superheater out-

let headers, the on-site tasks of visual inspection and measurements, crack depth determi-nation, component history including temperature exposure and metallurgy of removed head-er boat samples, all contribute to the establishment of a root cause.Also, the need for a deci-sion on immediate repair, replacement or continued service for a finite time, possibly underrestricted operating conditions, can be ascertained.

The utilization of a header or pipe spool piece in a detailed study has provided muchinformation on the history of damage accumulation. Also, calibration blocks can be machined

Component Damage Type Failure Cause Inspection/

NDT Technique Remedial Actions

Feedwater piping Wall thinningErosion-CorrosionOxygen pittingFlow accelerated corrosion

UT thicknessInternal videoAlloy analysis

MonitoringFeedwater controlReplacement

Economizer inlet headerLigament crackingTube stub thinningTube weld cracking

Thermal/corrosion fatigueErosion/corrosionThermal expansion fatigue

Internal videoUT thicknessMT examination

MonitoringEventual replacementWeld repair

Economizer outletpiping Internal crackingThermal (shock) fatigueEconomizer steaming

Internal videoReplication

Monitoring of componentsand temperatures

Downcomer pipingDamaged supports and

attachments

CorrosionAbnormal eventsThermal expansion

Visual inspectionMagnetic particle

examination

MonitorRepair

Lower water wall headersTee cracking

Tube stub cracking

Thermal expansion fatigue

Thermal/corrosion fatigue

MT examinationInternal video

UT shear waves

Repair

Replacement

Attemporator assembliesSpray nozzle and liner

assembly crackingThermal/corrosion fatigue

Dye penetrant testingInternal video

ReplacementRepairAdd dual spray feature

Cold reheat pipingCorrosion/pittingInternal cracking

Water inductionThermal fatigue

Visual inspectionInternal video

MonitoringRelocate componentsReplacement

Reheat inlet header SaggingOvertemperature exposureExternal piping loads

ReplicationHardness testingInspect cold reheat pipe

supports

Review boiler operationsAdd support steelTest pipe supports

Superheater crossoverpiping

Internal componentcracking

Thermal fatigue (attemperation)Internal videoUT shear wave of welds

MonitoringRelocate componentsReplacement

Secondary superheaterinlet header

Internal ligamentcracking

Thermal fatigue (attemperation) Internal videoMonitoringReplacement

Main steam pipingHot reheat piping

SaggingExternal weld cracking

Water inductionCreepThermal fatigue

Visual inspectionInternal videoBoat samplesReplicationUT shear waveMT examination

MonitoringReplacementRepair

Girth weld and ligamentcracking

Thermal fatigue and creep

MonitoringAnalytical studyOperational changeReplacement

Secondarysuperheater/reheateroutlet headers

Tube stub weld crackingThermal expansion fatigue and

creep

Visual inspectionInternal videoBoat samplesReplicationUT shear waveMT examination

Analytical studyRepair

Table 1 Typical boiler critical header and piping component problem areas


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from such pieces, and used for future testing and monitoring activities for similar compo-nents of that particular unit.

The case study results from the sagged reheat inlet header has highlighted the need forpaying close attention to the adjoining piping and supports and the support structure for evi-dence of overload conditions on the header, and possibly abnormal internal effects from the

upstream attemperators.Table 1 provides a summary of major boiler header and piping components, which

includes the types and causes of damage experienced by each, together with the recom-mended inspection and testing tasks and remedial actions required.

RECOMMENDATIONS

The pattern of performing condition assessment programs for boiler and piping compo-nents should be continued during each scheduled outage for a unit. The programs can bealtered based on previous history and results. Many of the items can be incorporated into amaintenance planning program. Monitoring of the major boiler and piping pressure compo-

nents should be a part of every scheduled outage plan, especially now with the increasedtime between shutdowns.

As part of the monitoring program, the piping supports should be inspected for evidenceof component deterioration in the form of physical damage, corrosion and functionality. If needed, the supports can be load tested in place, to ensure they are capable of carrying theiroriginal design loads.

For a header found to have circumferential weld, bore hole, or ligament cracking, the rec-ommended actions include documenting the visual inspections with internal and external

video tape recording. This can prove valuable for later review using video-analyzing equip-ment. The next on-site task would be to perform ultrasonic shear wave testing to obtain anestimate of crack depths, especially in the tube ligament fields. This information, together

with material property data and operating parameters, can then be input to stress analysisand fracture mechanics evaluations in order to confirm the suitability for continued opera-tion and to provide a definitive remaining life value for the component. The taking of andanalyzing metal boat samples from the outside surface of the header will provide muchinformation on the current microstructural condition, and of the crack morphology. Theseresults are also factored into the remaining life derivation. When the component is ulti-mately replaced, pieces of the header can then be evaluated to provide additional data on theroot cause of the cracking.

The data contained herein is solely for your information and is not offered,or to be construed, as a warranty or contractual responsibility.


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REFERENCES

1. DB Riley Field Report No. 97708, “Inspection and Assessment of Cracking in a Weldon High Temperature Superheater Outlet Header’, dated April 21, 1998.

2. DB Riley Field Report No. 200225,“Inspection and Assessment of Ligament Cracking in High Temperature Superheater Outlet Header”, dated November 16, 1998.

3. Power Magazine, May 1993 article entitled, “P91 Solves Superheater-Outlet-HeaderCracking Problem.”

4. DB Riley Technical Report No. 96523, “Condition Assessment of Reheat Inlet Headerand Cold Reheat Inlet Piping”, dated February 14,1997.

5. S.R. Paterson, T.A. Kuntz, R.S. Moser and H. Vaillancourt, Boiler Tube FailureMetallurgical Guide, Research Project 1890-09, Final Report TR-102433, ElectricPower Research Institute, Palo Alto California, October, 1993.

6. L.H. Toft and RA. Marsden, “The Structure and Properties of 1%Cr- 0.5%Mo Steel After Service in CEGB Power Stations”, in Conference on Structural Processes in

Creep, JISI/JIM, London, 1963, p. 275.7. DB Riley Technical Report No. 61933, “Evaluation of Hot Reheat Steam Piping Test

Spool Piece”, dated March 21,1997.

8. C.W. Marschall, C.E. Jaske and B.S. Majumdar, “Assessment of Seam-Welded Piping in Fossil Power Plants,” Final Report EPRI TR-101835, Electric Power ResearchInstitute, Palo Alto, California, December, 1992.

9. J.R. Foulds, R. Viswanathan, J.L. Landrum, and SM. Walker, “Guidelines for theEvaluation of Seam Welded High Energy Piping”, EPRI TR-104631, January, 1995.

10. J.F. Henry, F.V. Ellis, and C.D. Lundin, “The Effect of Inclusions as Controlled by FluxComposition on the Elevated Temperature Properties of Submerged-Arc Weldments,”

Weld Tech 88 - International Conference On Weld Failures, London, England.

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Rst-164 Condition Assessment of Boiler Piping & Header Components

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