ML20140E370

Rev 0 to CR 199700445, Fort Calhoun Station Root Cause & Generic Implications Rept Fourth Steam Extraction Line Rupture

ML20140E370
Person / Time
Site:	Fort Calhoun
Issue date:	05/09/1997
From:	Gasper J, Geschwender J, Amar Patel OMAHA PUBLIC POWER DISTRICT
To:
Shared Package
ML20140E365	List: ML20140E370 ML20140E380 ML20140E388
References
CR-199700445, CR-199700445-R, CR-199700445-R00, SRG-97-026, SRG-97-26, NUDOCS 9706120032
Download: ML20140E370 (35)

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i Fort Calhoun Station Root Cause and Generic Implications Report Fourth Stage Steam Extraction Line Rupture 4

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FORT CALHOUN STATION ROOT CAUSE AND GENERIC IMPLICATIONS REPORT FOURTH STAGE STEAM EXTRACTION LINE RUPTURE CR 199700445 i

PRC RECOMMENDS REVISION 0 3pPROVAL-SRG-97-026

$4Y 0 71997 t>HG MTG MINUTg4 A. R. Patel, Lead Evaluator Date Yb7

[. R. Geschw nder, Evaluator Date h5 W r/ shy f K. ' asper, P/er Review Team Member - CR Owner G I VD' ate l

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i FORT CALHOUN STATION ROOT CAUSE AND GENERIC IMPLICATIONS REPORT l

l FOURTH STAGE STEAM EXTRACTION LINE RUPTURE

" TABLE OF CONTENTS" 1

l SECTION TITLE PAGE SECTION 1.0 DETAILED EVENT DESCRIPTION........................

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l SECTION 2.0 SIGNIFICANCE OF EVENT...............................

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SECTION 3.0 ROOT CAUSE AN ALYSIS................................

2 3.1 G e n era l...........................................

2

~3.2 Hu man Performance...............................

3 3.3 Administrative / Programmatic........................

3 3.4 Management / Supervisory Oversight.................... 8 3.5 Training / Qualification...............................

9 3.6 E q u ip m e n t......................................... 9 3.7 Co n cl u s i o n........................................ 11 SECTION 4.0 GENERIC IMPLICATION ANALYSIS.....................

12 SECTION 5.0 ITEMIZED

SUMMARY

OF CAUSES......................

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" ATTACHMENTS" FAULT TREE CHART........................................ ATTACHMENT 1 DOCUMENTS REVIEWED................................... ATTACHMENT 2 D RAWING S................................................. ATTA CHMENT 3 PHOTOG RAPHS............................................ ATTACHMENT 4 CORRECTIVE ACTION RECOMMENDATIONS................ ATTACHMENT 5

1.0 DETAILED EVENT DESCRIPTION At 2022 on April 21,1997, with the Fort Calhoun Station (FCS) reactor operating at a nominal 100% power, the Control Room crew heard a loud noise, like an explosion, from the turbine building. This was followed immediately by a very loud continuous roar.

The crew concluded that a steam leak of unknown size had occurred. The Control Room personnel checked the reactor instrumentation and noted normal indications, with no change in Reactor Coolant System (RCS) cold-leg temperature, steam generator pressure or reactor power. The Shift Supervisor opened the Control Room door with another operator present to assess the location of the leak, and observed a large amount of steam flowing from the grating at the north end of the Turbine Building. The Turbine Buildmg was quickly filling with steam.

The source of the steam was a rupture of the extraction steam line from the fourth stage of the high pressure turbine to Feedwater Heaters FW-15A and FW-15B. The rupture occurred in 12-inch pining at the third elbow downstream from the turbine. This elbow is located at the north ena of the Turbine Building on the Mezzanine level behind several non-safety related Motor Control Centers (MCCs).

The Shift Supervisor directed that the reactor be manually tripped at 2023. The Primary Reactor Operator immediately tripped the reactor. Coincident with this action, a " Loss of Load" alarm was received on the Emergency Response Facilities (ERF) computer. The plant entered Emergency Operating Procedure EOP-00 and began the required post-trip actions. Emergency boration was initiated as a precautionary measure. Steam Generator pressure remained steady and began to approach a normal post-trip value. The Control Room crew had a concern that personnel might have been in the Turbine Building at the time of the piping rupture. The Security Shift Supervisor was contacted and requested to account for all personnel on-site at the time. This action was completed and it was determined that no injuries had occurred.

With plant conditions stabilizing, at 2045 the Shift Supervisor initiated the FCS Emergency Plan and declared a Notification of Unusual Event (NOUE). The Shift Technical Advisor contacted the Nuclear Regulatory Commission (NRC) to inform them of the NOUE, and the Control Room Communicator notified the States and Counties of the situation.

Motor Control Center MCC-4C3 and numerous associated 480 volt loads had de-energized, including the main turbine turning gear motor, the turning gear oil pump and the auxiliary oil pump for the running main feedwater pump. This MCC is located in the Turbine Building and supplies non-Critical Quality Equipment (non-CQE) loads. The steam release caused fire alarms and actuation of the Fire Protection System. Fire pumps l

FP-1 A and FP-1B started and Turbine Building sprinklers actuated. After verifying no j

fires and attempting to isolate sprinkler flow, both fire pumps were placed in Pull Stop.

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b Indication of a ground on DC Bus I was received, but current and voltage remained normal. Actions to address de-energized equipment and fire protection issues continued.

By 2345, conditions were determined to allow termination of the NOUE.

1 2.0 SIGNIFICANCE OF EVENT This event was significant from the standpoint of personnel safety, damage to the plant, and because it required an unplanned reactor trip. The ruptured high pressure steam extraction line released a large amount of steam, creating the potential for a fatality or severe injury. Fortunately, no personnelinjuries occurred. The steam release caused i

substantial damage to nearby electrical equipment. The actuation of the Turbine Building sprinklers also complicated the response to the event. An additional personnel safety 4

issue resulted from damage to asbestos insulation. The Turbine Building was contaminated by the asbestos resulting in the need to restrict access.

The rupture occurred in a non-safety related system. Reactor Protution System (RPS) loss-of-load limit switches were in the vicinity of the rupture, but are not credited in the Updated Safety Analysis Report (USAR) Section 14 safety analysis. A High Energy Line Break (HELB) can result in a harsh environment, jet impingement, and/or pipe movement which represent a threat to nearby equipment. Nevertheless, the consequences of the rupture with respect to effects on nearby equipment were bounded by the analysis of a Turbine Building Main Steam HELB in USAR Appendix M.

l The steam lirie rupture resulted in an uncontrolled heat extraction which has the potential to affect reactivity. However, the uncontrolled heat extraction was effectively stopped within less than one minute of the rupture, when the reactor / turbine were tripped. There was not a significant decrease in steam generator pressure. The effect on primary system temperature and reactivity were far less than assumed for a Main Steam Line Break in USAR Section 14.12.

Since the consequences of the event were bounded by USAR analyses, it is concluded that the event did not have significant nuclear safety implications.

3.0 ROOT CAUSE ANALYSIS 3.1 General This Root Cause Analysis (RCA) was initiated to investigate the causes of the extraction steam line rupture. Preliminary assessment of the pipe rupture suggests that it resulted from excessive pipe wall thinning caused by Flow-Accelerated Corrosion (FAC). A failure analysis was initiated for detailed investigation of the 2

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physical condition (s)/ mechanism (s) involved, and will document the findings in i

this area. This RCA provides a preliminary discussion of the apparent physical cause of the rupture (See Section 3.6). Final conclusions in this area will be provided by the failure analysis. This RCA focuses on assessing why the degraded condition of the piping was not identified prior to the event. This presumes that the failure analysis will support the preliminary indications that pipe thinning over a relatively long period of time was the cause of the rupture, and that significant thinning could have been detected well before the event.

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This investigation included interviews with several industry experts in FAC, maintenance personnel, and individuals responsible for the Erosion / Corrosion Control Program. The Erosion / Corrosion Control Program Basis Document, procedures, modifications, and Maintenance Work Orders were reviewed. Also, information relating to FCS experience with Erosion / Corrosion was reviewed.

The Fault Tree Analysis Method was used to aid in determining the causes of this event. (See Attachment 1).

3.2 Human Performance The primary human performance issue for this event relates to the application of engineering judgement in the selection of sites for ultrasonic inspections. Since this application of engineeringjudgement is performed within the context of the Erosion / Corrosion Control Program, it is addressed as a programmatic issue in i

Section 3.3.

3.3 Administrative / Programmatic The Fort Calhoun Station has an Erosion / Corrosion Control Program which is I

intended to predict, detect, monitor and mitigate erosion / corrosion wear in plant piping. The objectives of the Erosion / Corrosion Control Program are to identify susceptible piping areas, detect pipe wall thinning, establish replacement criteria and reduce erosion / corrosion wear rates. As such, this program serves as the means to coordinate efforts to prevent pipe ruptures associated with excessive pipe thinning. The initial revision of the Erosion / Corrosion Program Basis i

Document was approved on October 23,1990, however, the program basis document discusses Erosion / Corrosion Program component inspections performed during refueling outages back to 1987.

Under the program, FCS systems were evaluated to identify " susceptible" systems, from which sites would be selected for inspection. A total of about 780 inspections have been performed and documented in the Erosion / Corrosion Program. During each refueling outage, new inspection sites are added based on plant and industry experience. Selection ofinspection sites in " susceptible" 3

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systems has been the responsibility of the Erosion / Corrosion Control Engineer, l

and has been based on a number of factors, including: ranking of sites by l

computer model, industry experience, FCS experience, follow-up on previously inspected sites, follow-up on components that have been replaced, repeated inspections of selected areas for wear-rate trending, recommendations from plant personnel, and engineering judgment.

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Assessment of the Eventual Ruoture Site 1

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The rupture location was in a system that had 9:n categorized as " susceptible" to I

erosion / corrosion and had been incorporated i:.a the Electric Power Research l

Institute (EPRI) CHECWORKS analytical model, but had not been selected for inspection under the Erosion / Corrosion Program. The rupture site was a " sweep" elbow (with a pipe bend radius of 5 feet)in the 12-inch steam extrwtion line from the fourth stage of the high pressure turbine to feedwater heaters FW-15A/B.

Other sites in the fourth stage extraction line had been inspected, including several shorter-radius elbows, a tee and a reducer. These components had shown acceptable rates of wear. The Erosion / Corrosion Control Engineerjudged that the longer radius " sweep" elbow would have lower wear rates than shorter-radius elbows that had been inspected. This judgement was incorrect in this case.

l Industry experience and the information from the CHECWORKS model were consistent with the judgement that shorter-radius elbows generally experience higher wear rates than longer-radius elbows exposed to similar conditions.

l EPRI's CHECWORKS analytical model indicates that a " sweep" elbow (elbow l

bend radius = 5.0 D) is predicted to experience about a 30% lower rate of erosion / corrosion than a comparable "long-radius" elbow (elbow bend radius =

1.5 D) subjected to similar conditions. This event, however, illustrates that other factors can " override" this typical relationship.

Greater emphasis on consideration of other factors could have led to selection of the rupture site for inspection. For example, NRC Information Notice 89-53 discussed an event involving a rupture of a high pressure extraction steam line l

adjacent to a section of piping that had been replaced due to wall thinning. The l

OPPD response to the notice (memorandum PED-SSE-89-708S dated l

September 14,1989) indicated that more extensive ultrasonic examination of the l

high temperature /high pressure extraction steam piping system for l

erosion / corrosion was already scheduled. It also indicated that an additional l

visual examination of neighboring areas adjacent to any replacement areas will mitigate the occurrence of the incident described in the Information Notice. (This Information Notice and the OPPD response are a part of the Erosion / Corrosion Control Program Basis Document.)

The section of piping immediately upstream of the rupture site was replaced in 4

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l 1985 under Modification MR-FC-85-094 to address erosion / corrosion of the l

piping. The response to the Information Notice, together with information s

regarding the modification, identifies several factors that indicate that the rupture site would have been an appropriate candidate for mspection.

Industry experience (e.g., Information Notice 89-53, Significant Operating Experience Reports 82-11 and 87-03) has highlighted the susceptibility of i

high pressure extraction steam lines to wall thinning; Fort Calhoun experience (ref. MR-FC-85-94, MR-FC-80-102 and various l

Maintenance Work Orders) has highlighted the susceptibility of the extraction steam lines to wall thinning; Areas adjacent to piping replaced due to erosion / corrosion warrant examination (ref. PED-SSE-89-708S and NSAC-202L Section 4.4)

I The rupture site was downstream of piping that was replaced in 1985 due to erosion / corrosion (ref. MR-FC-85-94).

While elbow radius is a quantifiable factor that lends itself to direct comparison between potential inspection sites, elbow radius is one of several factors that influence wear rate. In this case, over-reliance was placed on thejudgement that i

" sweep" elbows would have lower wear rates than other inspected locations.

Over-reliance on elbow radius as a predictor of relative wear rate, with insufficient consideration of plant history and industry guidance, is considered the l

root cause of the failure to inspect the rupture location prior to the event.

No FCS inspection data on " sweep" elbows was available to correlate wear predictions to FCS data, as a result of no " sweep" elbows having been included in i

the inspection program. NSAC 202L Section 4.4 recommends inspecting components from each geometry type in the inspection selection. While NSAC 202L does not identify "long-radius" and " sweep" elbows as different geometry types, it does indicate the desirability of data on a variety of components. The failure to include " sweep" elbows in the inspection program is considered a contributing cause.

l Be of Plant Historv/ Industry Exnerience l

Discussions with the Erosion / Corrosion Control Engineer indicate that l

engineering judgement is used in determining the overall number ofinspection sites. The actual sites selected include: previously inspected sites that require inspection based on a calculated " Inspection Index;" sites requested by plant personnel; chemistry trending sites; sites selected based on industry events; sites i

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l selected based on CHECWORKS ranking data; small bore piping sites selected on the basis of engineeringjudgement; and a small number of random sites.

Limited documentation is available to clearly define the process for selecting inspection sites. For example, NSAC-202L and OPPD's response to Information Notice 89-53 indicate that consideration should be given to inspecting adjacent components when a component is repaired / replaced due to erosion / corrosion.

However, no detailed OPPD site selection criteria have been established to formally implement this type of consideration, nor are there specific requirements j

to document the basis for selecting the sites that are recommended for inspection.

Detailed site selection criteria could also provide guidelines for the use of CHECWORKS component rankings and/or projected wear rates (See "Use of CHECWORKS" for additional discussion). Lack of a detailed, proceduralized l

methodology for selecting inspection sites is considered a contributing cause.

Discussions with the ErosiordCorrosion Control Engineer indicate that documentation of plant erosion / corrosion experience is not readily retrievable.

Experienced personnel have been used as a resource, however, no documented summary of Fort Calhoun erosion / corrosion-related repairs / modifications has been generated. If plant experience information had been systematically j

assembled (e.g., a file or database of previous repairs / modifications resulting from erosion / corrosion problems), it could have been used as an important resource during site selections. For example, such information could be used to ensure that components in the vicinity of areas that have required past maintenance / modification are included in the scope of components inspected.

Incomplete utilization of plant history data is considered a contributing cause.

l Industry experience has been applied in the selection ofinspection sites. The Operating Experience Review Program addresses several important sources of industry experience including Institute of Nuclear Power Operations (INPO) and i

NRC operating experience documents. Also, OPPD is a member of the CHECWORKS Users Group (CHUG), which specifically focuses on erosion / corrosion issues. However, OPPD's involvement in CHUG has been limited in that CHUG meetings (which occur twice a year) have not been routinely attended, and OPPD has not participated in or previously used the CHUG Plant Experience Database. Incomplete utilization ofindustry experience resources is considered a contributing cause.

Incomplete utilization of plant history data, incomplete utilization ofindustry experience resources, and lack of a detailed, proceduralized methodology for selecting inspection sites, combined to increase the possibility that valuable l

information would not be considered in the site selection process. This is also i

discussed in Section 3.4 as a management / supervisory oversight issue.

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Use of CHECWORKS OPPD began using the EPRI CHEC analytical model in 1987 to assist with identifying single phase piping areas that could be susceptible to erosion / corrosion. This model was used by OPPD until 1993. During 1993, EPRI's CHEC models were updated with the issuance of the EPRI CHECMATE modeis, and two-phase piping was added. OPPD converted the CHEC analytical model to the CHECMATE analytical model in 1993. No inspection data were i

l included in these models. The portions of susceptible piping included in these CHECMATE models are identified and described in Piping and Instrumentation Diagrams (P&lDs) included in the Erosion / Corrosion Control Program Technical l

Manuals. Review of these P& ids and the descriptions in the Technical Manuals, indicates that some of the susceptible piping that is suitable for modeling was not i

included in these CHECMATE models.

The CHECMATE analytical model was used by OPPD until 1993. OPPD l

converted the CHECM ATE analytical model to EPRI's CHECWORKS analytica' model in 1994. Ultrasonic inspection data available at the time were added to the models. A CHECWORKS " Pass 1" analysis provides projected wear rates which l

are used for ranking of components.

Some limitations on the validity of FCS predicted wear rates and/or component rankings obtained through the use of CHECWORKS include:

Baseline wall thickness data is only available for recently replaced components Variations in material composition (e.g. chromium content) can subsantially affect wear rates Some lines that are suitable for modeling have not been incorporated into l

the FCS CHECWORKS model Recent inspection data was not incorporated into the FCS CHECWORKS model l

Theoretical wear predictions have significant uncertainties The OPPD CHECWORKS model has not been independently verified.

Overall, the ability to use system modeling to predict specific locations of excessive wear is limited. The Erosion / Corrosion Control Program did not establish specific guidelines, goals and training on the verification, 7

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comprehensiveness, updating and use of the CHECWORKS model. This is considered a contributing cause. (The training aspect of this contributing cause is discussed in Section 3.5).

Use of Current Plant Exnerience The Erosion / Corrosion Control Program Basis Document and Procedure

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SS-PM-MX-0800," Ultrasonic Inspection of Station Piping" address the concept of selecting inspection sites from " susceptible" systems using industry experience, engineeringjudgement and CHECWORKS software. These documents also address calculation of an " Inspection Index" from the results of ultrasonic testing.

This " Inspection Index" indicates when the tested location will need to be tested again. SS-PM-MX-0800 also addresses sample expansion when the pipe wall thickness oflarge bore piping is found to be less than 70% of nominal wall.

SS-PM-MX-0800, Revision 0, was issued on November 8,1994, and was based on procedure PM-PIPE-1 which was originally issued on February 23,1987.

An elbow in the tenth stage steam extraction line from the low pressure turbine failed in 1996 because of FAC, and was replaced during the 1996 refueling outage. The importance of this failure is that this elbow was considered to have limited susceptibility to FAC, yet it failed. Information of this type warrants i

assessment ofits implications on the Erosion / Corrosion Control Program. While tenth stage steam extraction line components had been inspected previously, and additional components were inspected in response to this failure, no documented evaluation was generated to address the impact of new plant experience on the program, and address whether it indicated a need for a general expansion of the scope ofinspected sites. The number of sites inspected each outage has decreased from one outage to the next, in all but one of the outages since 1990. The lack of established guidance to address evaluation of the impact of new plant experience on the program is considered an additional aspect of the lack of a detailed, proceduralized methodology for selecting inspection sites. (This was previously identified as a contributing cause; see "Use of Plant History / Industry Experience.")

3.4 Management / Supervisory Oversight Section 3.3 addresses some issues related to the degree of reliance on the Erosion / Corrosion Control Engineer to properly consider a number of complex factors in selecting sites for inspection. As previously discussed, incomplete utilization of plant history data, incomplete utilization ofindustry experience resources, and lack of a detailed, proceduralized methodology for selecting inspection sites, combined to increase the possibility that valuable information would not be considered in the site selection process. When the program was in 8

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l development, personnel changes took place without complete transfer of historical knowledge. Reliance was placed on the Erosion / Corrosion Control Engineer to I

become familiarized with information that could be necessary for maintaining the program. A systematic self assessment of the program had not been performed prior to the event. Lack of adequate management / supervisory oversight, independent knowledge, and assessment is considered a contributing cause.

3.5 Training / Qualification Training was provided to program personnel. Program personnel have successfully completed OPPD's technical staff training. Training was also provided on EPRI's CHECMATE and CHECWORKS, including modeling and evaluation of analytical data.

As previously discussed, OPPD is a member of the CHECWORKS Users Group (CHUG), which specifically focuses on erosion / corrosion issues. However, OPPD's involvement in CHUG has been limited in that CHUG meetings (which occur twice a year) have not been routinely attended, and OPPD has not participated in or previously used the CHUG Plant Experience Database.

Incomplete utilization ofindustry experience resources was previously identified as a contributing cause (See "Use of Plant History / Industry Experience" in i

Section 3.3). Similarly, incomplete utilization of plant history data was previously identified as a contributing cause. Both these issues affect the ability of the Erosion / Corrosion Control Engineer to maintain awareness of plant and industry experience. Also, although training was provided on CHECWORKS software, this training may not have adequately addressed such issues as interpretation of output and limitations of the software. (See "Use of CHECWORKS" in Section 3.3).

Qualifications / certifications for the personnel conducting the non-destructive examinations were also reviewed. Non-Destructive Examination (NDE) personnel were qualified and certified to perform the non-destructive examination thickness measurements that were made.

3.6 Equipment Flow Accelerated Corrosion (sometimes referred to as erosion-corrosion) is a process whereby the normally protecting oxide layer on carbon or low-alloy steel dissolves into a stream of flowing water or a water-steam mixture. The bare metal surface is re-oxidized, and the process continues. The rate of metal loss depends on a complex interplay of many parameters including water chemistry, material composition and hydrodynamics. To the naked eye, the damaged surface has a variable :ppearance. Under a small degree of magnification a scalloped, wavy or 9

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orange-peel appearance is also observed. In water / steam flow a " tiger striped" appearance is often observed.

The steam quality in the fourth stage steam extraction line is approximately 92%.

This indicates that two phase flow was in the line. Visual examination of the rupture section of the " sweep" elbow was performed by several industry experts.

The preliminary conclusion is that the area exhibited classic wear characteristics associated with Flow Accelerated Corrosion (FAC). The visual examination of the rupture area showed:

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Areas of smooth wear 2.

Areas of pitting surrounding the rupture area 3.

The area down stream of the rupture exhibited a " tiger striped" appearance 4.

Areas of scalloped appearance wear 5.

The wear was concentrated in the extrados of the elbow.

l The rupture occurred at a " sweep" elbow in the 12-inch extraction steam line from the fourth stage of the high pressure turbine. The elbow material was ASTM 106 Grade B.

L A " fish-mouth" rupture occurred in the sweep elbow with an approximate size of 54 inches long and 18 inches wide. The steam release damaged the back of a non-safety related motor control center and damaged some insulation on other piping.

Additional discussion of the effects of the steam release are addressed in " Damage Assessment Report for the Break in the Extraction Steam Line."

l Pending completion of the failure analysis of the ruptured pipe, Flow-Accelerated l

Corrosion (FAC)is considered an apparent root cause of the rupture. Final conclusions in this area will be provided by the failure analysis. Other potential mechanisms (e.g., droplet impingement, vortex theory, effects of high chromium l

content piping upstream of the rupture elbow) will also by considered in the failure analysis.

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3.7 Conclusion Preliminary information suggests that the physical cause of the steam extraction line rupture was Flow-Accelerated Corrosion (FAC). A failure analysis has been initiated to furth:r analyze the physical cause of the rupture and assess other potential mechanisms.

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Based on the preliminary assessment, it is assumed that pipe thinning occurred l

over a relatively long period of time, and that significant thinning coijd have been l'

detected well before the event. Since the site had not been inspected, the process l

of selection ofinspection sites was reviewed. It was determined that over-reliance l

was placed on one factor, the typical relationship between elbow radius and wear rate, in omitting the site from previous inspections. Consideration of other factors (e.g, the generally high susceptibility of high pressure extraction steam piping, l

plant maintenance / modification history, and the desirability ofinspecting components adjacent to areas where piping has been replaced due to j

erosion / corrosion problems) could have resulted in selection of the site for l

inspection.

A factor that contributed to the situation described above is that there was no detailed, proceduralized methodology for the process of selecting inspection sites.

Such a methodology could define the susceptibility evaluation process and identify situations that would require expansion of the selected inspection sites.

Guidance from applicable sources (such as NSAC-202L) could be incorporated into this methodology.

i Industry experience and plant history information are both important l

considerations during the selection of appropriate inspection sites. However, l

incomplete utilization of plant history data, and incomplete utilization ofindustry experience resources increased the possibility that valuable information would not l

be adequately considered in the site selection process. Lack of adequate management / supervisory oversight, independent knowledge, and assessment l

contributed to this.

l Additional factors that may have contributed to the event were failure to include l

" sweep" elbows in the inspection program, and lack specific guidelines, goals and L

training on the verification, comprehensiveness, updating and use of the CHECWORKS model 11 SRG-97-026 I

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4.0 GENERIC IMPLICATION ANALYSIS A search of erosion / corrosion related events on Nuclear Network was conducted. There l

are several INPO Significant Event Reports (SERs), Sigaificant Operating Experience Reports (SOERs), Operating Plant Experiences (OEs) and other information available from the Nuclear Network System. These reports were reviewed for applicability and l

lessons learned. In addition, a CHUG database on industry experiences with erosion / corrosion was reviewed.

l Erosion / corrosion is clearly a significant generic concern with respect to high pressure steam extraction piping. Industry experience also indicates that several other areas have been a significant issue in the industy such as feedwater, moisture separators, vents / drains, and condensate. Clearly this event has generic implications that must be addressed to ensure that adequate inspections have been performed and that these inspections encompass a wide variety of component types.

The programmatic, management / supervisory and training issues discussed in the report also have potential generic implications. Each of the following issues could have implications for other FCS programs:

Value of detailed procedural guidance Adequacy of utilization of plant data / industry experience l

Adequacy of guidelines / training on the use of software Adequacy of management / supervisory oversight and independent knowledge / assessment.

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l 5.0 ITEMIZED

SUMMARY

OF CAUSES/ GENERIC IMPLICATIONS 5.1 Apparent Root Cause - Flow-Accelerated Corrosion (FAC) (A failure analysis has been initiated to further analyze the physical cause of the rupture.) (Cause code -

UFGZ " Material / Equipment Worn")

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j 5.2 Root Cause - Over-reliance on elbow radius as a predictor of relative wear rate, l

with insufficient consideration of plant history and industry guidance. (Cause code - PEWE "Over reliance on Favorite Indication")

5.3 Contributing Cause - Failure to include " sweep" elbows in the inspection program. (Cause code - MSYE " Inadequate Implementation ofInternal Operating Experience")

5.4 Contributing Cause - Lack of a detailed, proceduralized methodology for selecting inspection sites. (Cause code - MSWA " Inadequate /No Standards, Policies, Administrative Controls")

5.5 Contributing Cause - Incomplete utilization of plant history data. (Cause code -

MSXB " Lack of Depth in Evaluation / Review")

5.6 Contributing Cause - Incomplete utilization ofindustry experience resources.

(Cause code - MSYF " Inadequate Implementation of External Operating Experience")

5.7 Contributing Cause - Lack of specific guidelines, goals and training on the verification, comprehensiveness, updating and use of the CHECWORKS model.

(Cause code - MSWA " Inadequate /No Standards, Policies, Administrative j

Controls")

5.8 Contributing Cause - Lack of adequate management / supervisory oversight, independent knowledge, and assessment (Cause code - MSWE " Inadequate Enforcement")

5.9 Generic Implication - Need to ensure that adequate inspections have been performed and that these inspections encompass a wide variety of component types.

5.10 Generic Implication - Need to ensure that identified progranunatic, management / supervisory and training issues are considered with respect to other FCS programs, i

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4th stage extrachon steam line ruptures j

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Excessive

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thinning of walls Thinning of pipe of pipe war not detected l

(Cause 5.1) prior to fadure l

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Pipe war section not inspeded Pipe materialis System fluid 4

g su coens are l

pipe intenor due to FAC Erosion Corrosio f

FAC conducive to FAC Program Coordinator g

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dd not select site for i

e l

l inspection t.

_._______a A

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A B

C D

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(Failure analysis D in plant operating I

[information not yetl Engineering judg.mt experience with industry Experience NSAC 202L inspection used to conclude i

( completed

. son / corrosion of did not prompt site recommendation was N

y' sweep ebows did not i

system did not prompt selection i.71 applied require inspection v

site selection L___--___

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I Lack of management / supervisory oversight and in-<!epth knowledge / assessment of Erosion / Corrosion Program l ATTACHMENT 1 I

(Cause s.m FAULTTREE ANALYSIS I

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I Page i of s l

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A Engineering judgment used to conclude sweep el bows did not require inspection A-

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Expectation that sweep elbows experience lower Acceptable wear rates were identifed in rates of wear than shorter radius elbows in simHar shorter radius environments sections of pipe in (Cause 5.2) same pipe run Available information and experience indicates CHECWORK, Pass 1 Lack of data on FCS sweep elbows generally predicts lower wear rates swee elbows experience lower wear on sweep elbows rates n

AL-_

Failure to inspect sweep Limitations of the Limitations on the data elbow type geometries CHECWORK model entered into model (Cause 5.3) i Inadequate policy / guidance / training to ensure appropriate use of ATTACHMENT 1 sonware (Cause 5.7/5.8)

FAULT TREE ANALYSIS Page 2 of 5 1-

B in plant operatrng l

experience with erosion / corrosion of system dri not prompt site selection A~

No established guidance incomp! ele d'h2ation of to apply plant experience p! tnt historical data with wear related problems A

A inadequate policy or administrative control for inadequate irnplementation of intemal applying intemat operating operating experience experience related to (Cause 5.5/5.8) erosion / corrosion (Cause SA/5.8)

ATTACHMENT 1 FAULTTREE ANALYSIS Page 3 of 5

C Industry Experience did not prompt site selection A-t incomplete use of industry operating experience d

i EPRI database IN-89-53 information not Limited involvement in 1

applied to previous failure CHUG W nnation not utdized by in system OPPD g

g 1

IN-89-53 information not inadequate incorporated into program implementation of (Cause SA/5.8) extemal operating experience (Cause 5 6/5 8)

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ATTACHMENT 1 FAULT TREE ANALYSIS Page 4 of 5 m

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i ATTACHMENT 2 DOCUMENTS REVIEWED i

i Program Basis Document Erosion / Corrosion Control, Revision 7, dated February 1997.

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Fort Calhoun Station Erosion / Corrosion Program Assessment Report, dated May 2,1997.

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Damage Assessment Report for the Break in the Extraction Steam Line, dated May 3,1997 I

l EPRI NSAC 202L Rev.1," Recommendations for an Effective Flow-Accelerated Corrosion l

Program," November 1996.

l EPRI NP-3944, " Erosion / Corrosion in Nuclear Plant Steam Piping: Causes and Inspection Program Guidelines," April 1985.

l l

EPRI NP-591 I M, " Acceptance Criteria for Structural Evaluation of Erosion / Corrosion Thinning i

l in Carbon Steel Pipier July 1988.

EPRI Report TR-102066, " Seismic and Dynamic Reliability of Erosion / Corrosion Piping Components" l

SOER 82-11," Erosion of Steam Piping and Resulting Failure," dated November 17,1982.

l SOER 87-3, " Pipe Failures in High-Energy Systems Due to Erosion / Corrosion,"

l March 20,1987.

l SER 6-95, " Condensate Pipe Break Due to Flow-Accelerated Corrosion," dated i

February 6,1995.

SER l-87, " Erosion / Corrosion Induced Failure of Feedwater Piping" l

SER 88-84, " Extraction Steam Line Break" i

i NUREG-1344, " Erosion / Corrosion-Induced Pipe Wall Thinning in U.S. Nuclear Power Plants,"

April 1989.

i Information Notice 93-21, " Summary of Staff Observations Compiles During Engineering Audits or Inspections of Licensee Erosion / Corrosion Programs," dated March 25,1993.

Information Notice 91-18, "High Energy Piping Failures Caused by Wall Thinning,"

March 12,1991.

j Information Notice 86-106, "Feedwater Line Break," dated December 16,1986.

i

- = - -

ATTACHMENT 2 (Continued)

Information Notice 89-53," Rupture of Extraction Steam Line on High Pressure Turbine,"

June 1989.

IE Bulletin No. 87-01," Thinning of Pipe Walls in Nuclear Power Plants," July 1987.

l i

Generic Letter 89-08, " Erosion / Corrosion Induced Pipe Wall Thinning," May 2,1989.

l Memorandum FC-1052-85," Water Pipe Wall Erosion Downstream of Flow Restricting Device" Memorandum FC-686-88," Review of the Evaluation and Disposition on SER l-87 Memorandum FC-1573-88," Response to Management Action Log No.880157" Memorandum PED-SSE-89-486S," Response to NRC Generic Letter 89-08," dated May 5,1989 Memorandum PED-SSE-89-708S, CID 890558/01," Rupture of Extraction Steam Line on High Pressure Turbine" Memorandum PED-SSE-90-0446S," Ultrasonic Equipment for Detecting Minimum Wall Thickness," dated May 3,1990 Memorandum PED-SSE-93-0625," Response to NRC IEN 93-21" Dated June 15,1993 Quality Control Procedure QCP-332," Gridding Procedure for Erosion /Coronion" j

i Quality Control Procedure QCP-331," Ultrasonic Thickness Measurement Procedure for Erosion / Corrosion" i

Quality Control Procedure QCP-200," Personnel Certification" SS-PM-MX-0800 " Ultrasonic Inspection of Station Piping" PM-PIPE-1, " Ultrasonic Inspection of Station Piping" Control Room Log Post Trip Reviews Event Notification Worksheet i

I i

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l ATTACHMENT 2 (Continued)

MR-FC-80-102, "6th Stage Extraction Erosion," completed 1983.

MR-FC-81-112, " Steam Erosion of Blowdown Piping," completed November 7,1981 MR-FC-85-94," Extraction Steam Elbows," completed December 5,1985.

MR-FC-89-036,"S/G Blowdown Tank Erosion," completed May 11,1990.

IS 1126,"SEN 99, Recurring Event: Steam Line Rupture Caused by Erosion / Corrosion," dated May 27,1993.

1 OE 5847," Erosion / Corrosion Event Causes Sequoyah Units 1 and 2 to be Shutdown," dated March 8,1993.

OE 6999, " Flow Accelerated Corrosion (FAC) of Extraction Steam Lines inside the Main Condenser," dated December 15,1994.

OE 8154," Steam Rupture - Update #3 to OE 8042," dated December 9,1996.

OE 8055, " Steam Rupture - Update #2 to OE 8042," dated October 4,1996.

OE 7152, " Extraction Steam Leak," dated March 15,1995.

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ATTACHMENT 5 1

CORRECTIVE ACTION RECOMMENDATIONS 4

i CONDITION REPORT #:

9700445 RCA REV #:

0 l

Corrective Action Item #:

1 RCA Cause #:52 Corrective Action: Complete failure analysis of ruptured elbow and identify any additional corrective actions based on this analysis.

(Assign to: R. L. Phelps)

Corrective Action Item #:

2 RCA Cause #:5.2. 5.3. 5.5. 5.6 Corrective Action:

4 Prior to startup evaluate, inspect (if susceptible to FAC if there is reason i

I to believe FAC is occurring and if not previously inspected) and replace (if required) possible components identified by the following a)

All sweeps in susceptible systems.

b)

Additional systems or parts of systems not included in the original susceptibility analysis.

c)

Components identified by industry team in high priority systems.

d)

Components downstream of replaced piping or components in high priority systems.

e)

Components whose minimum wall is insufficient to operate for the l

remainder of the cycle based on the revised wear projections.

(Assign to: J. K. Gasper)

Corrective Action Item #:

3 RCA Cause #:5.2. 5.3. 5.4. 5.5. 5.6. 5.8 Corrective Action:

Before identifying inspection sites for the 1998 refueling outage, develop and l

obtain approval for a detailed, proceduralized methodology for selecting

{

inspection sites and reviewing inspection results.

This methodology must j

incorporate plant and industry experience. The procedure must include management concurrence on site selection and disposition of inspection results.

(Assign to: B. Lisowyj) l

Corrective Action Item #:

4 RCA Cause #:

5.f Corrective Action:

Update. verify and maintain the CHECWORKS models consistent with industry standards.

a)

Update the CHECWORKS models.

b)

Verify the CHECWORKS models.

c)

Incorporate inspection data from 1995 and 1996 outages into the CHECWORKS models consistent with industry practice.

d)

Place procedural controls on the CHECWORKS models including documentation of changes and incorporation of modifications and maintenance.

(Assign to: B. Lisowyj)

(Note: This action must be completed before Correction Action Item # 3 can be completed.)

Corrective Action Item #:

5 RCA Cause #:5.7. 5.8 Cerrective Action:

Provide training on the use of CHECWORKS and the appropriate application of CHECWORKS results in an erosion corrosion program to appropriate engineering, supervision, management. PRC and assessment personnel. (Assign to: J. K.

Gasper)

Corrective Action Item #:

6 RCA Cause #:

5.8 Corrective Action:

Use industry peers in assessment of specialized programs such as erosion corrosion. (Assign to: R. L. Andrews)

Corrective Action Item #:

7 RCA Cause #:

5.9 Corrective Action:

In the assessment of programs that rely on sampling methods assure an adequate variety of component types are incorporated into the program.

(Assign to R. L. Andrews) l

l I

Corrective Action Item #:

8 RCA Cause #:

5.10 l

Corrective Action:

Conduct an independent evaluation of the assessment processes at Fort Calhoun to determine causes for the ineffective identification of issues in the l

erosion corrosion fire protection and emergency preparedness programs that were subsequently identified by independent teams and agencies.

(Assign to R. L. Andrews)

Corrective Action Item #:

9 RCA Cause #:

5.2 throuah 5.8 i

Corrective Action: Appropriately address the findings and conclusions of the self assessment team.

(Assign to: J. K. Gasper)

I SUBMITTED BY:

8/A/A APPROVED BY: 0 % U CA W UCROWNERNp

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PRC CHAIRPERSON l

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