ML20149L208
| ML20149L208 | |
| Person / Time | |
|---|---|
| Site: | Fort Calhoun  |
| Issue date: | 07/25/1997 |
| From: | Howell A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | Gambhir S OMAHA PUBLIC POWER DISTRICT |
| References | |
| 50-285-97-09, 50-285-97-9, EA-97-280, NUDOCS 9707310192 | |
| Download: ML20149L208 (111) | |
See also: IR 05000285/1997009
Text
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- July 25, 1997
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S. K. Gambhir, Division Manager
Production Engineering
Omaha Public Power District
Fort Calhoun Station FC-2 4 Adm.
P.O. Box 399
Hwy. 75 - North of Fort Calhoun
Fort Calhoun, Nebraska 68023-0399
Dear Mr. Gambhir:
SUBJECT: PREDECISIONAL ENFORCEMENT CONFERENCE SUMMARY
On July 21,1997 representatives of Omaha Public Power District met with NRC personnel
in the Region IV office located in Arlington, Texas to discuss the apparent violation
identified 'a NRC Inspection Report Number 50-285/97-09. The conference was held at
the request of Region IV.-
The licensee presented a summary of the causes for the apparent violation and their
corrective actions.
The attendance list, NRC handout, and the licensee's presentation are encloseo to this
summary. In accordance with 10 CFR 2.790 of the NRC's " Rules of Practice," a copy of -
this summary and its enclosures will be placed in the NRC Public Document Room.
Sincerely,
b
h Arth r T. Howell 111, Director
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Division of Reactor Safety ,
Enclosures:
1. Attendance List
2. Licensee Presentation ( k
3. NRC Handout i
Docket No.: 50-285 01OObb
License No.: DPR-40
9707310192 970725
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gDR ADOCK 05000285
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Omaha Public Power District -2-
cc w/ enclosures:
James W. Tills, Manager
Nuclear Licensing
Omaha Public Power District
Fort Calhoun Station FC-2-4 Adm.
P.O. Box 399
Hwy. 75 - North of Fort Calhoun
Fort Calhoun, Nebraska 68023-0399
James W. Chase, Manager
Fort Calhoun Station
P.O. Box 399
Fort Calhoun, Nebraska 68023
Perry D. Robinson, Esq.
Winston & Strawn
1400 L. Street, N.W.
Washington, D.C. 20005-3502
Chairman
Washington County Board of Supervisors
Blair, Nebraska 68008
Cheryl Rogers, LLRW Program Manager
Environmental Protection Section
Nebraska Department of Health
301 Centennial Mall, South
P.O. Box 95007
Lincoln, Nebraska 68509-5007
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Omaha Public Power District -3-
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E-Mail report to T. Boyce (THB)
E-Mail report to NRR Event Tracking System (IPAS) l
E-Mail report to Document Control Desk (DOCDESK)
bec to DCD (IE01).
bec distrib. by RIV: l
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Regional Administrator DRS-PSB
DRP Director MIS Systern
Branch Chief (DRP/B) RIV File
Project Engineer (DRP/B) Branch Chief (DRP/TSS) !
Resident inspector
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DOCUMENT NAME: R:\_FC\FCSUM.JL
To receive copy of document, indicate in box: "C" Copy without enclosures "E" = Copy with enclosures "N" = No copy
SRA:DRS ,l E D:DRPA g D:DRS [r),Y/, E l l
JFShackelfordJ s TPG W M ATHo % I)I
07d_f97 l, 074fS7 1
07/25/97 "
OFFICIAL RECORD COPY
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Omaha Public Power District -3-
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E-Mail report to T Boyce (THB)
E-Mail report to NRR Event Tracking System (IPAS)
E-Mail report to Document Control Desk (DOCDESK)
bec to DCD W
. bec distrib. by RIV:
~ Regional Administrator DRS-PSB
DRP Director MIS System
Branch Chief (DRP/B) RIV File
Project Engineer (DRP/B) Branch Chief (DRP/TSS)
Resident inspector
.
DOCUMENT NAME: R:\_FC\FCSUM.JL
To receive copy of document, indicate in box: "C" Copy without enclosures "E" = Copy with enclosures "N" = No copy
SRA:DRS ,
E D:DRPA, ,gg D:DRS f,Y/, E
JFShackelfor4 TPG W M ATHoMMI
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OFFICIAL RECORD CO')Y
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ENCLOSURE 1
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Fort Calb.aun Station ,
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Predecisional Enforcement Conference Attendance List
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PREDECISIONAL ENFORCEMENT CONFERENCE ATTENDANCE
j LICENSEE / FACILITY Omaha Public Power District
Fort Calhoun Station
DATE/ TIME July 21. 1997. 10:30 a.m.
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CONFERENCE LOCATION Region IV. Training Conference Room l
Arlington. TX
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NRC REPRESENTATIVES
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PREDECISIONAL ENFORCEMENT CONFERENCE ATTENDANCE
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LICENSEE / FACILITY Omaha Public Power District
Fort Calhoun Station
i DATE/ TIME July 21, 1997. 10:30 a.m.
! CONFERENCE LOCATION Region IV. Training Conference Room
Arlington. TX
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- LICENSEE REPRESENTATIVES
L NAME (PLEASE PRINT) ORGANIZATION TITLE
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ENCLOSURE 2 ;
Fort Calhoun Station
Licensee Presentation
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l OMAHA
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PUBLIC POWER .
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DISTRICT
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! Fort Calhoun Station
- Main'
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Prec ecisional Enforcement Conference
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- July 21,1997
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Opening Remarks
Introductions
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Gary Gates
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Agenda
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Sudesh Gam ahir
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Agenda
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o Operational Overview
Ross Ric enoure
o Maintenance Rule
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Jim Tills / John Johnson / Ken Dowdy
o Assessments and Corrective Action
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Update
Joe Gas aer
o OE Program Assessment
Dick Andrews
o Summary and OPPD Persaective
Sudesh Gambhir
o Closing Remarks
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Gary Gates
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Operational Overview
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Ross Ridenoure
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- Operational Overview .
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o Event Overview.
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o Primary Plant Impact.
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o Secondary Plant Imaact.
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o Operational Safety Significance. .
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l Overview of the Rupture.
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i o Major steam rupture in 4th stage
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extraction steam line. :
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l o Reactor tripped within 19 seconds.
! O Crew entered emergency procedures
and stabilized the plant quickly.
o Crew responded in a decisive, timely
manner.
o NOUE declared and ERO activated.
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l Primary Plant Impact -
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j o Prior to the trip the steam rupture
! produced no changes in reactor power,
- steam generator pressure, or other
l primary parameters. .
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o Normal Post-Trip response observec. 4
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o Operatinc crew made a cecision to
emergency borate the reactor.
o No significant challenge to the operating
crew.
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j. Sec6ndary Plant Impact .
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One MCC was c e-energizec .
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i Some piaing in the immediate area o"the
! rupture was bent / twisted. .
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! Wetting of Equipment.
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! Steam Volume contained in the Turbine
j Building.
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- Turbine Building basement anc
mezzanine.
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Intermittent ground alarms on a 480V bus
and DC bus #1.
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No adverse plant effects were observed
due to t1ese intermittent grounds. '
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tO Qperational Safety .
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j Significance
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! o Event effectively mitigatec by the
j o aerating crew.
[ Minimal effect on the arimary plant.
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l Minimal effect on t7e secondary plant.
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lO Minimal reduction in Fire Protection System
l capability.
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o Not a significant operating challenge to
i the crew.
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Maintenance Rule
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Jim Til s / John Johnson /
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Ken Dowdy
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Maintenance Rule .
- Discussion
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o Scoping of Systems Under the
Maintenance Rule.
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Goal Setting / Performance Criteria
requirements -
o Performance Monitoring of the
O Extraction Steam System.
EC program monitoring effectiveness.
o Use of Industry Operating Experience.
Program Development.
Post-Event Corrective Actions.
o Imalementation of Maintenance Rule
Requirements.
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Monitoring Under the .
Maintenance Rule
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o Sco3ing of Extraction Steam.
Included within scoae of program as part of
t1e Main Feedwater System.
- No failures of Extraction Steam had caused a
plant trip at FCS. O
- Industry review indicated that Extraction Steam
piping could potentially cause a plant trip.
Classified as Nonrisk Signi"icant
- NUMARC guidance.
Reviewed and Aaproved by an FCS Expert
Panel. O
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! o Extraction Steam SSCs were monitorec
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l NUMARC guidance provides that Plant
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Level Criteria are ap aro ariate.
i Plant Level Performance Criteria
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established were:
! - No Plant Trip due to MPFF.
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l - No Unplanned Capability Loss due to MPFF.
! - No Safety System Actuations due to MPFF.
System Level Performance Criteria:
- System must be available (100%) when required
for power operation.
g Reviewec and A3provec by Ex3ert
Panel.
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Monitoring Under the .
Maintenance Rule /\ cont >1'
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o Evaluated against Plant and System
Level Performance Criteria.
Review of SSC failures and maintenance
history was performed from 7/1/92 to
6/30/95.
System monitoring ongoing since 7/1/95. i
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No failures prior to the rupture were
identified that exceedec the Performance
Criteria.
o System placec in Category (aX2} of the
rule.
o Reviewed and Approvec by Expert
Panel.
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l- Monitoring Under the .
l Maintenance Rule (cont)
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o Piping considerec effectively controllec
l by Erosion Corrosion Program.
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l Review incicatec wel-developed inspection
j prog ram.
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Proactive replacement of piping prior to
reaching minimum wall thickness.
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l Status of Extraction Steam .
l Piping After April 21,1997
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i o Actions taken as a result of the
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Extraction Steam Line Break.
l Piant Level and Main Feedwa":er System l
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Performance Criteria exceeded.
Cause Determination performed based on
RCA and Failure Analyses. g
- Identified Failure as MPFF.
- Recommended all FAC-susceptible piping be i
placed in Category (a)(1). I
o Findings and Recommendations l
Reviewed and Approved by Expert l
Panel.
o Additional Evaluation.
All plant system piping reviewed. $
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l Summary of Maintenance
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o Industry operating experience was
properly taken into account. ('" 9.3.3}
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o The extraction steam system classifiec
! as "nonrisk .significant". ('" 9.3.2}
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lO Guidance. allows monitoring using plant
level criteria.
- No automatic reactor scrams.
- No unplanned safety system actuations. l
- No unplanned capability loss factor.
System level aerformance criteria was also
established.
- Requires 100% availability during power
operation.
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Summary of Maintenance. .
Rule Compliance
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o The failure history on extraction steam
was reviewec for a four year period
prior to July 1996. {'" 9.3.3}
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No problems were detected involving
extraction steam (no through wal leaks ag
no alping below minimum wall).
o Based on failure history, extraction !
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steam did not require saecific goal
setting and was correctly monitored in I
accordance with 10CFR50.65(aX2}.
{'"9.3.4)
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l Summary of Maintenance .
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l Rule Compliance
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i o Extraction steam was monitored by the ;
j EC program. At the time of Maintenance
l Rule implementation the EC program
l was judged to be ef ective. .
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- Proactive replacement of piping
iO mponents.
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Effective in meeting performance criteria
and preventing repetitive MPFF.
Highly susce atible extraction steam
components extensively monitored (70%
sites inspected).
Multia e ssessments indicated t7e
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3rogram was an Industry leac er.
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l Summary of Maintenance.
l Rule Compliance
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l o The April 21,1997 failure caused both
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plant and system level performance l
! criteria to be exceeded.
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l Failure was the initial MPFF.
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l' No extraction steam MPFF had occurrec ,
prior to Maintenance Rule implementation.
This is the first known large radius swee a
failure in the industry.
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l Summary of Maintenance.
lU Rule Compliance
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l o Based on the failure the following
l actions were taken:
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! A cause determination was performed.
FAC susceptible piping was placed in
l category (a)(1).
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i Goals were established.
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Industry experience was again used during
! both the goal setting phase and cause
, determination. (C 9.4.1 and 9.4.4)
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- o A determination was made on whether
j other piping systems within the staae of
l the Rule were being effectively
j o monitored by the EC program.
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l o While a Significant Event, the Failure Is
Not, in Itself, a Violation.
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o The Rule Worked As Intended.
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l o Extensive Corrective Actions Were #
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o Industry Experience was utilized per
NUMARC guidance.
o No Violation of the Maintenance Rule
Occurred.
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Assessments and .
l Corrective Action
l0 Update
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! Joe Gasper
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l Assessments
Objective
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To ferret out the root cause
and any other program , I
deficiencies or problems.
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Assessments .
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o Corrective Ac: ions
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Corrective -
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Assessments Actions & G
Results
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LAdditionalInspections and
lU Replacements
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l o 23 Sites Inspected
o Replaced because of FAC
l 4th stage sweeps.
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6th stage 18 "- 45o elbow - Conservatively
l Replaced - Would Have Reached Design
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O Minimum Wall in 3 0 3erating Cycles.
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o Replaced for other reasons
l 6th stage 18"- 45o elbow and pipe - Weld
) fit-up aroblem aroduced locally high
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turbulence.
Heater Drain - Three Identical 3 " Pipes
[ downstream of orifices - Visual examination
{ of pipes found no localized wear.
In lusions orlaminations may have causec
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l erroneous UT indications.
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Altrrn Ccrporttiin
Technical Report N . 97152-TR-01 '
Revision 0
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NOTE: % WALL LOSS CALCULATED FROM too. AT INSPECTION DATE INDICATED.
FORT CALHOUN 4th STAGE EXTRACTION
STEAM LINE TO F.W. HEATERS ,,g;;yggL,
Geometry & Inspection / Replacement
Sununary of 4th Stage Extraction
.
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l Replaced Components
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i o Conclusion
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Two sweeps required replacement:
l - The ruptured sweep elbow and .
l - The 10" sweep due to FAC (below rninimum
l wall).
!O Two components showing FAC were
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l conservatively replaced (above minimum
l wall}.
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l Four com 3onents replaced for other
! reasons.
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Update to Assessments -
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o Failure Analysis
o FAC Code Verification -
o FAC Program Implementation Review
Additional Information Concerning
Replaced Com aonents.
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- . Failure Analysis .
- Completed
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l FPI and Altran Concluded:
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j The Root Cause was Flow Accelerated ,
l Corrosion.
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! There is Evidence of High Velocity Water
- DropletImpingement.
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Complex hydraulic arofile aroduced large
variation of oxide accumulation and
damage characteristics in failed sweep
elbow.
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33
- -
.. - _ _ . _ _ _ _._ _ _ _____
_ _ _ _ _ . _ _ _ _ - _ - -
'*
i .
l. FAC Program .
io
,
!
- s u&2.?ttw*m :: . ,. s
o Code Verification
!
! !
CHECWORKS Modeling
'
l
l -
!
1
l BRT-Cicero Mode ing
O Program Implementation Review
!
l Use of Plant 0 3erating Experience
i
i
! Site Selection Methodology
l Use of Industry Operating Experience
i
!
i O
i
i 34
. .- _
Altran C:rporrti:n
Technical Report . 97152-TR-01 ,
O
- '
-
g5 N %, :
-
0t 2$>, N !
\, '#
IN
khgk '
b4IA s N
< 1 Ng y
7
IN -.
o. r# 199
4 N
{93
.
ing
I((,,@. "4
,<gf' . ce2
%$,$,?,hb lt@ ' &?** 9
*"44 , ,
- $$,3
"
%Qpp
hO Cl ?. ;
o
g >
1 E
2 9a7
O
Mx
4
l
NOTE: % WALL LOSS CALCULATED FROM t AT INSPECTION DATE INDICATED.
FORT CALHOUN 4th STAGE EXTRACTION , ,
STEAM LINE TO F.W. HEATERS ,,ggg g g ,, j
l
Geometry & Inspection / Replacement l
Summary of 4th Stage Extraction
.
. _ _ _ _ _ _ _ _ _ - _ - _ - _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _
.
..
l CHECWORKS Modeling. l
!o
i
I
~ '
. < _ . .. _ .,
!
o Update and Validate CHECWORKS
using 95,93 and 97 inspection data.
l
j Parallel trains modeled.
l Model Verified. -
j - Modeling errors corrected.
I - Irispection data matrices entered for
lO
!
components.
! o Model updated with all data available
j before 1993 outage.
l o Line correction factor.
Value reflects accuracy of predicted wear
! rate.
Acceptable range between 0.5 and 2.5.
$ age 2 4 6
Factor 2.368 0.370 0.695 35
.
9
- CHECWORKS Modeling. .
e
,
(Cont)
yygny.;
o Measured versus Predicted Wear Plot
shows half of data points outside +/-
50% range.
.
O Conclusions: e
A good corre ation is not established
between measured and aredicted wear.
CHECWORKS should not be used to
determine the wear status of components
that have not been inspected.
e
36
.-
.
$
! BRT-CICERO Modeling .
lO
.
. ; .2i"'Q
l o Code used by EDF.
!
l o Fourth stage modeled.
o Results ~
i
j Predicted wear at end of Cycle 16 of 0.429
! inches.
iO
i Prediction ~is conservative to observed wall
,
loss of 0.057 to 0.151 inches depending on
l actual initial wall thickness and a failure
thickness of 0.050 inches.
o Differences between Cicero and
CHECWORKS.
Uses component vs line correction factors.
Calculates individual component prediction
O uncertainty.
37
.
Use of Plant Operating -
e
Experience
mem_
.
o RCA Contributing Cause: Incomplete
utilization of plant operating experience
l
Additional replacement data identified l
.
Now classed as a root cause g
o Additional corrective action
Research, maintenance and configuration
changes done before program !
implementation in 1988 ,
O
38
i
_ - - __ _ _ _ _ _ _ _ _ _
l Site Selection Criteria .
io
! ,
! I
'
r .,um m ,x+.n -
l o Applied NSAC 2 2L Guidance using I
! data available prior to 1993 outage
l Inspect Highest Wearing l
l
Components. -
,
! Shortest Relative Remaining Service Life.
l O One Component from each parallel train.
i
j Immediately downstream of control valve
l
i
and orifices. :
l One com aonent in each two phase line of
! 3iping.
'
Industry Experience.
Plant Experience.
Replacec components and components
within two pipe diameters of replaced
O components.
Unusual geometries. 39
.
-
_ _ _ __ _ ___ _ _ _ _
l
Use df Industry Operatin(
Experience
..=~r u-
o Research of CHUG data base identifiec
no additional information and no
information relative to sweeps.
.
o Inspections basec on industry operatir$
experience. !
70% of Extraction Steam sites inspected l
before 1997 forced outage. !
48% of the Heater Drain sites insaectec. l
38% of tie Circulating Water sites
inspected.
l
35% of the Condensate sites inspected.
O 1
40
. _ . .
\
_ _ - _ _ _ _ - _
.
9
.
FnC Implementation .
l
i
Review Conclusions
~ . r., ., m, ye.
l o Industry experience effectively used.
!
}
!
o Plant exaerience not effectively usec.
$ CHECWORKS shou d not 3e used to
predict wear for components that have
not been inspected in the 4th stage line.
o Unique flow conditions may exist in t1e
4th stage line.
O
41
.
- Current Corrective Actions-
t e
i
4
Status
'
~
.._m ,. -
,_...s...
-
o Conduct additional inspections to
- develop PASS 2 mode s for
- CHECWORKS.
- o Evaluate on-line radiography for small
bore piping.
e
- o Evaluate replacing high wear piping with
wear resistant piping.
o Evaluate additional moisture traps on
extraction steam piping to reduce wear.
o Provice additional training.
e
42
_ .
__ __
_ _ _ _ _ _ _ _ ___ _ ,
li Current Corrective Actions
!O
l; Status
., ,. .l.,(l ? ~
'
'#
.
.
o Work with EPRI to share experiences
l with the industry.
l
l
~
i
l
l o Work with EPRI to improve modeling for
l O large radius sweeps.
i
l
!
!
o Work with EPRI to better understanc
j effects of oxygen concentration on
j secondary systems.
!
!
!O
!
!
- 43
. -- . . _ . - --- -_ - _ .- - _._ -.
.
.
-
.
i *
O
-
. nn
'<r<s9' w .u %. . m ,s.,
-
, . . . , - _ . , ..
1
.
1
i
OE Program .
Assessment
e
l
l
Dick Andrews
e
44
, _ . . _ _
._ - - -._ .-- _ _ _
.
e
.
OE13rogram Assessment
i O
l
' ~
'
,..,. i..i ., [ .I. . . ' .
'
i.
o Focus on Use of Operating Experience.
'
101 Programs Evaluated. ;
! To 3ics Reviewed.
I - Issues warrant additional Management .
!
attention?
- Other locations known to be better?
i
.
l0
j
- is industry experience being obtained and
utilized?
j - is all other needed information being obtained?
l - Are there barriers to using information obtained?
1
j - Is information receipt adequate and being
4
properly utilized?
- Are personnel contacts and meeting participation
adequate?
- Have industry experts or peers provided input or
review?
- Is electronic information received adequate and
being utilized?
O
- Is printed information received adequate and
being utilized? 45
j .
.
OE Program Assessment . . ;
e;
!
,
..... 2 " ="5 2 *L _ . !
o Significant Results.
Oversight groups more aware of need to include !
1 information utilization when performing audits,
surveillances, and assessment activities. .
Heightened program owner awareness of ownership
and the need to use external as well as internal g
information.
Discussion of nuclear operating experience at plant -
morning meetings has been implemented.
!
s Too many people rely solely on the formal OE
program for their external information. .
Formal as well as informal industry sources of
information have been identified.
O
46
_.
_
- O !
!
!
-
. J.ffy c . . ; . . . -- _ ; . 2.. f; , F,' . ..
-
-
.. .<.,.m m m m y w . . .n .. - .
)o 13 of 101 Programs Identifiec for
l Additional Management Attention.
!
! Protective Coatings
~
Setpoint Contro -
Design Basis
!O Radiological Consequences
l Asbestos Management
ASME ISI/IST Program
l
j Tagging
Chemical Contro
Hazardous Materials
Nondestructive Examination (NDE)
Bills of Materials
Offsite Dose Calculation, Radiological
O Effluent Monitoring
M&TE y
- - . _ _ . _ _ ___ _.
O
- OE Program Assessment -
- r -
o Programs identified for Technical
Review. i
!
Erosion and Corrosion Programs
PRA Program
1
SG Inspection Program
n ASME ISI/IST Program g!
AOV Program
MOV Program
Relief Valve Program
Check Valve Program ;
9 PM Program
Procurement Engineering Program
Fuel Reload Analysis
EEQ Program
SQUG Program
g
Containment H 2 Generation 48
!
- _ _ . _ _ _ . _ _ _ _ _ _
. .
j
!
!
l .
l I
o
i
,
4
l
h ' - ~i: l m;%&C%MGV , ifll< l
- .. m.a.u ... . . . _ m , a m.w. . ..
I
!
I
.I
!
!
!
!
!
!,
l
,
t
Summar and .
l OPPD Perspective
!o
l
)
'
Sudesh Gambhir
'
!
!
i
l
l
1
l
l
5
i
i
,! O
4
0
<
49
i . - . .- _
-
i
Summary and .
- OPPD Perspective
y.n;3 .
o This Is a Serious Situation Which Must !
l Be Prevented and Not Repeated. !
o Significant From an Industrial Safety .
Standpoint. !
o Significant From Plant Availability
Standpoint.
!
Not a nuclear safety significant event. l
- Did not present a significant operational
challenge.
e! l
50 !
_ _ - - _ _ _ _ _ _ _ - _ _ _
..
- -
.
Maintenance Rule
- O
- Compliance
!
i
. : ver _ .
=
- o Rule requirements were met
- i
i
l Piping was aroaerly monitored.
l
l Appro ariate aerformance criteria were i
j established. I
O Industry wide operating experience was ;
utilized.
Monitoring was in place.
- With the exception of 4th stage extraction steam
piping, the program was effective.
o Further Assessment Is Planned to
Evaluate Implementation Against
O " Excellence."
51
- _ _ _ _ - _ _ _ _ _ _ _ _
, .
.
l FAC Program .
i
e
i
j Jl2 *2L L.:
i
j o FAC program used for monitoring under
j the Maintenance Rule.
l o Implementation of FAC program was
! weak. -
!
l o Industry experience was factored into
l the inspecti.on program. e
! CHUG Database does not lead to
inspecting sweeps. -
70% of sites in the extraction steam piping
were inspected prior to rupture.
l
o OPPD was deficient in utilizing are-1988
Fort Calhoun exaerience.
o FAC program limitations (Ref. EPRI doc.
I
NSAC 202, rev.1 page iv).
-
Tab 2
e
52
_ _ _ _ _.__ _ . _ _ _ _ _ _ _
- - .
l. Assessments .
i0 '
!
! .
. w e a m w w o ,e :: -
.
. .:. n .a ...; .
.
~,m.~,- : .,s. . ,.
!
!
!
!
~
l OPPD has conducted
! multiple assessments to
0
! ferret out the root cause
l and any other program
i
! deficiencies or problems.
!.
1
i
l
lO
l 53
.-. _.
. .
. .
I
'
j .
-
l Corrective -
l
Assessments Actions & O
l Results
-
.... _: C = N"' . . .
+ Lessons
Learned
. Updated
O
i
M Short Term
Corrective
lU4 E+ o rec
i
i
C- E O
54
_
. . . _ _ _ . _ . . - _ . _ . - . . . . _ . _ _ _ _ _
l
l Other Considerations .
l
- O
! :
l
!
.
m ,_ _
l .
..
m v s o a a ,:.ma,.
!
!
l
o Corrective Actions
l
l Extensive corrective actions including
i consideration for generic impact. .
i
, o Historic Issue
lO
l Problem occurrec because ofinadequate
treatment o" re alacement 3rior to 1989.
!
!
! Missed op 3ortunity to inspect in 1985.
o Lessons Learnec
Lessons learned lave been shared with the
O industry.
55 ,
1
.
_ . _ _ _ _ _ _ _ _ _ _ - - - - - - -
-
l. -
l
4
i
4
i
'
.
e
-l
}
-, . ~ ~ 4' ?.' i,7MC . . ' '[ N '
-
. . . , . . . . . . . . . , . . . . . . . ,
.
i
!
1
>
,
~
l
,
Closing Remarks
i
i
i
e
I
s
a
- Gary Gates
i
5
+
J
l
9
56
._
1
1
.
1
METHODOLOGY OF MONITORING EXTRACTION STEAM UNDER THE l
^ MAINTENANCE RULE I
l
White Paper in response to NRC Inspection Report 50-285/97-09
July 9,1997
1. PURPOSE,
The purpose of this document is to explain the methodology used to determine
the scoping status of Extraction Steam components, the methods used to monitor
these components, and the basis used for determming the monitoring of these
components.
l
2. REFERENCES
I
a) NRC Inspection Report 50-285/97-09
b) NEI 93-01 Revision 2, Industry Guidelines for Monitoring the .
Effectiveness of Maintenance at Nuclear Power Plants
c) NRC Regulatory Guide 1.160, Monitorine the Effectiveness.o_f
Maintenance at Nuclear Power Plants
d) NRC Inspection Manual - Inspection Procedure 62706, Maintenance Rule
e) NUREG-1526, Lessons Learned from Early Imolementation of the
- Maintenance Rule at Nine Nuclear Power Plants
f) Questions and Answers from the August 1993 NUMARC Maintenance
Workshops
g) FCS Program Basis Document, Maintenance Rule i
'
h) FCS Maintenance Rule Implementing Instructions (MRII)
'
i) FCS System Scoping Manuals (SSM)
l
3. MONITORING OF EXTRACTION STEAM PRIOR TO THE APRIL 21,
1997 EVENT !
a) Details of Extraction Steam Scoping
The Extraction Steam System (ESS) at Fort Calhoun Station (FCS) is
considered to be within the scope of the Maintenance Rule per
10CFR50.65(b)(2)(iii). These SSCs were included within the scope of the
rule since they can cause a plant trip. FCS had not experienced a plant <
trip due to failure of extraction steam components, but industry experience
indicated that extrac+ ion steam could cause a plant trip at FCS.
Components within the ESS are monitored as part of the Feedwater
.
d
I
whitel.do::
-- -- ..
'
.
.
Heaters functional groups.' The components within these functional .
groups are not risk significant according to the plant PRA.2 The ESS is
not a Safety Related system, and there are no safety related functions for
extraction steam listed in the plant Design Basis Documents or the USAR.
Accordingly, the functional groups which include extraction steam are
classed as Non-Risk / Operating functional groups.
b) Monitoring of Extraction Steam
I
i) The functional groups containing extraction steam were monitored
using plant level criteria in accordance with 10CFR50.65(a)(2).
Guidance provided by NEI states that non-risk significant /
operating SSCs are to be monitored using plant level performance
criteria. This approach is endorsed by the NRC in Reg. Guide
1.160.'
'
ii) Components within these functional groups have been monito. red
for failure by the plant NPRDS failure reporting process since
1991, when Revision 4 of the NPRDS Reporting Guidance Manual
(RGM) was implemented. The FCS Maintenance Rule Program
(MRP) adopted NPRDS failure reporting methodologies and
expanded NPRDS guidance to cover all components within the
- PN scope of the Maintenance Rule. Revision 5 of the NPRDS
Reporting Guidance Manual (December 1994) removed
- requirements for monitoring many component types that require
monitoring under the Maintenance Rule. As a result, MRP
personnel created a Reporting Guidance Manual that supplemented
the NPRDS RGM and included instructions for continued
'
monitoring of through wall leakage of piping. These instructions
were later incorporated into Maintenance Rule Implementing
Instruction (MRII) -3, Maintenance Rule Failure Renortina. With
'
the cessation of NPRDS reporting, MRII-3 was revised to include
all necessary guidance for Maintenance Rule failure reporting, and
the NPRDS RGM is no longer used by the MRP as a reference.
iii) In accordance with NEI guidance,5 a review of the failure history
- of functional groups including extraction steam SSCs was
! performed. This review consisted of two tiers. One was the
4 ' Ref. i) Volume 15, Main Feedwater. Tab 10, LPA(B)HTR IPA (B)HTR HPFWHT - Feedwater
- Heaters
,
2
Refj) 9.133.F.
'
Ref. b) 93.2
d
i , Ref. c) 1.73
V ' Ref. b) 933
2
whitel. doc
'
.
.
review of existing plant specific NPRDS and Maintenance Rule *
data from CHAMPS. The second tier involved the review of
Maintenance Work Documents from July 1,1992 through June 30,
1995 to determine if additional failure reporting other than that
already contained in CHAMPS was required. It should be noted
that NEI guidance only requires the licensee to perform a review
of history for a maximum of three years prior to the I
implementation date of the rule.6 There were no problems
detected involving extraction steam that would require goal
setting.7 Based on these reviews, it was determined that the
functional groups containing extraction steam SSCs did not require i
goal setting and were being correctly monitored in accordance
with 10CFR50.65(a)(2). While NEI guidance was used to make
this determination, the methodology used by FCS to determine the
proper monitoring level of extraction steam SSCs is dso discussed
in NUREG-1526 and endorsed in Reg. Guide 1.160.30
iv) Extraction steam piping, as well as piping from other systems,"is i
monitored by the plant's Erosion / Corrosion Program (ECP). The
ECP sets individual, component level performance criteria for
piping covered within its scope. The FCS MRP does not set !
individual, component level performance criteria, but makes use of i
^
existing programs as allowed by law" and NEI guidance. 2 l
Effectiveness of the ECP is monitored by the MRP using two
methods. These methods are discussed below: l
a) Failure Reporting Process - Through wall leakage of piping
is considered a component failure' per MRII-3. As such, a
i
failure investigation must be performed and a report
generated into the CHAMPS database when a leak occurs.
Since extraction steam SSCs are monitored at the plant l
level, a non-catastrophic failure (leak) of an extraction l
steam line would not exceed MRP performance criteria
unless plant level performance criteria (as described in
MRII-2, Settine Performance Criteria) were exceeded.
However, MRII-5, Component I ailure Analysis, allows for
the elevation of an SSC to monitoring under
.m
' Ref. b) 733
' Ref. i) Volume 15, Main Feedwater. Tab 15. Initial Performance Assessment
- Ref. b) 9.2.4
' Ref. e) 2.4.1
Ref. c) 1.9
" Ref. c) B Use of Existing Licensee Programs
" Ref. b) 7.0
v " Ref f) Appendix C, Section 12, Question 50
3
whitel. doc
- _ . _ _ . _ _ _ ._- . . _ _ _ _ _ . _
'
.
. I
10CFR50.65(a)(1) even if performance criteria is not .
^
exceeded, if the situation warrants.
!
b) A catastrophic failure of extraction steam piping would I
cause plant level perfonnance criteria to be exceeded (if ,
deemed an MPFF), or would exceed system level criteria I
(Availability of 100% while power operation is desired) l
even if the failure was not mairtenance preventable." In !
effect, MRP performance criteria adequately monitors the
ECP since piping is monitored not only at the plant level
(as allowed by law), but also at the system and, to some
extent, the component level.
v) A detailed analysis of the ECP by the MRP was not required as
part of the maintenance rule implementation effort. NEI 93-01
states:
Utilities can utilize their existingprogram results to
support the demonstration that SSCperformance is being
effectively controlled through preventive maintenance. Jf
verformance monitorine indicates that SSC verformance is
unacceptable. then the cause determination (Section 9.4.4)
e verformed when SSC verformance is unacceptable should
correct any eauipment or vrogram deficiency. "
The FCS MRP was monitoring the effectiveness of the ECP, and
when the ECP was found to be ineffective in ensuring the
performance of extraction steam piping, a cause determination was
performed and goals were set as required by the rule.
c) Conclusions
The following conclusions can be drawn about the status of the ESS prior
to the steam line break of April 21,1997:
i) Extraction steam SSCs were correctly within the scope of the FCS
MRP.
ii) Functional groups containing extraction steam SSCs were
correctly included for monitoring under 10CFR50.65(a)(2) based
on a review of maintenance history.
" Ref. i) Volume 15, Main Feedwater. Tab 2, Main Feedwater System
y " Ref. b) 7.0
4
A v :. doc
_ _
'
.
.
^ iii) A failure such as that occurring on April 21,1997 would have -
caused both plant level and system level performance criteria to be
"
exceeded. MRIl-6, Placement of SSCs into Category (a)(1) or I
(a)(2), would have prompted a cause determination as required by
law and NEI guidance. Such a cause determination would cause a I
review of the effectiveness of existing programs as well as current
, performance criteria."If the ECP was fcand to be ineffective,
functional groups containing extraction steam SSCs would be
monitored under 10CFR50.65(a)(1) until effective corrective I
l
action was taken. This meets the requirements of Reg. Guide
1.160" and NEI 93-01."
4. MONITORING OF EXTRACTION STEAM AFTER THE APRIL 21,1997
EVENT l
a) Actions Taken Directly as a Result of the April 21,1997 Event
,
i) The failure of a large radius sweep in the fourth stage extractio'n
line on April 21,1997 caused operations personnel to manually
trip the reactor. The failure of the pipe is classed as an equipment
failure per MRP failure reporting guidance." This requires an. '
investigation of the incident and the generatior, of a failure report.
'S Failure reporting procedures require that a determination be made
.
as to whether the failure was maintenance preventable or not.
^
Industry experience is also to be used when making this
determination.20 The MRP reviewed the preliminary root cause
analysis (RCA) performed by plant personnel. The preliminary
root cause analysis determined that there were several
programmatic deficiencies in the ECP, and that the failure could
,
have been prevented. The failed section of piping was also sent
'
out for a failure analysis to two different vendors. Completion of
the MRP failure report is pending the results of these failure
analyses.
The failure of the piping caused a loss of the functions.1 groups
'
containing the failed pipe. The failure also caused a plant trip.
MRP personnel had intended to wait until the completion of the
failure analyses before performing a cause determination. This
would be necessary in order to determine if the failure was indeed
" Ref. h) MRII-6. Placement of SSCs into Cateeory (aYl) or (aV2),5.6
" Ref. c) 1.9
" Ref. b) 9.43 and 9.4.4
" Ref. b) MRIl-3djaintenance Rule Failure Reportine. 6.2
v ** Ref. h) MRII-3. Maintenance Rule Failure Reportine.14.29
5
whitel. doc
.. . . - ..
.
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an MPFF as stated in the preliminary RCA and therefore a
violation of plant level criteria. However, since system level
availability performance criteria were also exceeded (which are
applicable even if the failure is not an MPFF), a cause
2
determination was performed as required by NEI guidance and
-
Reg Guide 1.160.2 This cause determination concluded that the
ECP, in its present state, did not adequately monitor Flow
Accelerated Corrosion (FAC) suseptible piping per
10CFR50.65(a)(2). Therefore goal setting would be required
under 10CFR50.65(a)(1). Corrective actions already completed
were reviewed, and goals were set to insure completion of
additional corrective actions. The question of monitoring of the
ECP was asked of the NRC at an industry conference and the
, following answer was given:
Programs are not in scope; only SSCs andperformance. . .
.
A firstfailure ofa SSC within the scope ofthe Maintenance
- Rule due to errosion / corrosion would require an effective
cause determination and corrective action. A .second
l failure ofthe same kind uvuld require goal setting and
- monitoring. .
^
In accordance with the above, the ECP was not placed into
category (a)(1); rather all FAC suseptible piping is currently being
monitored in accordance with 10CFR50.65(a)(1).24
i 25
ii) In accordance with applicable guidance , the plant made use of
'
industry experience during the goal setting phase of the cause
l
determination. Personnel from other utilities were part of tha ECP
self assessment, and other industry experts were called upon to
assist with the failure analysis and to provide advice for program
'
improvements.
b) Other Actions Taken as a Result of the April 21,1997 Event
.
A review was performed by MRP personnel to detennine if other piping
systems currently within the scope of the rule were being effectively
monitored by the ECP or by other preventive maintenance (PM)
2
- ' Ref. b) 93.4
22
Ref. c) 1.7.1 Cause Determination
- Ref. f) Appendix C, Section 16, Question 6
FCS MRP Cause Determination alfile\cc249705 Revision 0
28
v Ref. b) 9.4.1
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programs.26 This evaluation resulted in the piping for three additional -
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systems to be transferred from rnonitoring under 10CFR50.65(a)(2) to !
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monitoring under 10CFR50.65(a)(1). While these systems were being
monitored under system and functional group level performance criteria,
'
no evidence could be found that piping was being specifically monitored .
I
in any way other than the MRP failure reporting process. It should be
noted. that monitoring of these systems was not ineffective since the
"
failure reporting process had already detected piping problems that had
contributed to unavailability that lead to the Instrument Air Compressors
being placed into category (a)(1) in January 1997.27
4
5. FINAL CONCLUSION
. Upon reviewing the documentation listed in Section 2 of this paper, and
j reviewing the monitoring of extraction steam piping prior to the April 21,1997
event as well as corrective actions taken after the event, MRP personnel must
conclude that this event did not constitute a violation of 10CFR50.65. This .
conclusion is based on the following points:
) therefore monitoring at the plant level was appropriate.
A b) The Maintenance Rule only required a three year review of maintenance
history to determine the level of monitoring necessary for these SSCs. No
problems were detected during the review period. In addition, the
,
proactive replacement of several extraction piping components by the
ECP led MRP personnel to believe that the ECP was successful in
detecting piping deterioration prior to failure. As such, there were no
grounds for goal setting for these SSCs prior to the April 21,1997 event.
This is in accordance with 10CFR50.65(a)(2) which states " monitoring as
specified in paragraph (a)(1) ofthis section is not required where it has
been demonstrated that the performance or condition ofa structure,
system, or component is being efectively controlled through the
performance ofappropriate preventive maintenance, such that the
structure, system, or component remains capable ofperforming its
intendedfunction. "
c) The purpose of the Maintenance Rule is to monitor the effectiveness of
preventive maintenance and take appropriate corrective action when
preventive maintenance is found to be ineffective. Paragraph (a)(1) of the
rule requires that "each holder ofan operating license . . . shall monitor
FCS MRP Analysis efar\cc249706
FCS MRP Cause Determination alfile\l4069701
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the performance or condition ofstructures, systems, or components,
against licensee-established goals, in a manner sufficient to provide l
reasonable assurance that such structures, systems, and components . 1
are capable offulfilling their intendedfimetions. Such goals shall be l
established commensurate with safety and, where practical, take into 1
account industry-wide operating experience. When the performance or
conclition ofa structure, system, or component does not meet established
goals, appropriate corrective action shall be taken. "
d) Extraction steam piping at FCS was being monitored by the MRP at a
level that was in accordance with NEI 93-01, Revision 2, as endorsed by
NRC Reg. Guide 1.160. When these performance criteria were exceeded,
comprehensive corrective actions were taken and all requirements of NEI
93-01 were performed as to the re-catigorization of the SSCs involved.
e) Industry operating experience was taken into account during the initial
scoping of extraction steam SSCs, and this experience resulted in the ,
inclusion of extraction stream within the scope of the Maintenance Rule.
Industry experience was also taken into account in the setting of goals
after plant level performance criteria had been exceeded.
I
f) The failure in question is not a repeat MPFF. The failed component is a
m large radius sweep, and there is no available industry information
indicating that these components are susceptible to accelerated FAC,
Preliminary failure analysis results also indicate that the flow rate within
the affected piping was considerably higher than expected due to the
configuration of the piping. NEI 93-01 defines MPFF and repeat MPFF as
follows:
An initial MPFF is thefirst occurrencefor a particular SSCf r
which thefailure results in a loss offunction that is attributa!!e to
a maintenance related cause. An ininial MPFFis afailure th:
would have been avoided by a maintenance activity that has n, t
been otherwise evaluated as an acceptable result (i.e., allowed sa
run tofailure due to an acceptable risk).
A " repetitive" MPFF is the subsequent loss offunction (as defined
above) that is attributable to the same maintenance related c.=?
that haspreviously occurred (e.g., an MOVfails to cine because a
spring pack was installed improperly -- the next tir.e this MOV
fails to close because the springpack is installed 'mproperly: the
MPFF is repetitive and the previous corrective c : tion did not
preclude recurrence). A second or subsequent loss offunction that
resultsfrom a different maintenance related cause is not
l
v considered a repetitive MPFF (e.g., an MOVinitiallyfails to close
8
whitel. doc
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because a springpack was installed improperly - the next time it
^ . fails to close, itsfailure to close is because a set screw was
improperly installed: the MPFF is not repetitive). " .
l
The current failure is the first functional failure of an extraction steam
pipe at FCS due to an ineffective ECP. It is also the first failure of a large
radius sweep due to FAC during the historical monitoring period required ;
by the rule. As such, it is an initial MPFF and not a repeat MPFF. Gther i
extraction steam components (small radius elbows, reducers, etc.) were
being comprehensively monitored by the plant ECP, in part due to the
available industry operating experience considering these components to
be a problem. Since this is not a repetitive event, the failure in question is
not a violation of 10CFR50.65.
.
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g Ref.b) Appendix B
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T;;tra Engineering Group, Inc. t toucomeacsw sweet suite 800 r esephone (seos est 4622
,
Westogue, Conneco' cut 06069 USA Fa phone (860) SS15524
r.
1
July 17,1997 l
97-FCA-203
Mr. Joseph K. Gasper i
Omaha Public Power District 1
5 miles North of Fort Calhoun NE on Highway 75
Fort Calhoun Station
P.O. 399 ,
Fort Calhoun, NE 68023 USA !
Dear Joe:
Encimed please find the final version of Tetra Engineering Report TR-97-009 entitled " Fort ;
Calhoun Flow Accelerated Corrosion Assessment of Extraction Steam Line".
.
Sincerely,
Frederick C. Anderson
A Vice President Engineering Services
-
e-mail: FAnderson_ Tetra @compuserve.com
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v' Engineering & Services forIndustry
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TR-97-009
Fort Calhoun
Assessment of Extraction Steam Line !
!
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cT('g
Prepared For Omaha Public Power District
By Tetra Engineering Group, Inc. !
July 17,1997
1
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W Tetra Engineering Group, Inc.
USA: 110 Hopmeadow Straet, Suite 800, Westogue, CT, 06089 (1).860.651.4622
France:Immeuble Petra B, it.P. 272, 06905 SOPHIA AN11POUS (33).4.92.96.92.54
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W revo engineenne croup. Inc.
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Contents .
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Introduction 1
,
BRT-Cicero Code 2
'
Fort Calhoun 4* Stage Extraction Steam Line 4
Comparison of BRT-CICERO to CHECWORKS 5
Conclusion -
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References 8
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Appendix A 9
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TR-97 009 Fort Calhoun FAc Assessment of Extraction Steam Line Contents e i
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Introduction
On April 21,1997 a sweep elbow in the 4* stage extraction line of the Fort
Calhoun Nuclear Power Plant ruptured. The cause of the rupture was determined
to be flow accelerated corrosion.
A review of the flow accelerated corrosion program at Fort Calhoun was initiated
following the rupture. One facet of this review is a attempt to determine why the
existing program failed to identify the thinned component piior to rupture. The
Fort Calhoun program used the EPRI CHECWORKS computer code to identify
potential thinned components for inspection. An alternate methodology was
developed by Electricit6 de France for predicting flow accelerated corrosion in
power plant components. The EdF code is entitled BRT-CICERO.
This report contains the results of a BRT-CICERO analysis of the Fort Calhotm
4* stage extraction steam line.
een
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TR-97 009 Fort Calhoun FAC Assessment of Extraction Steam Line introduction .1
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Tstra Engine 1nng Group, Inc
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BRT-Cicero Code
The BRT-CICERO' code was developed by M. Bouchacoun and F. N. Remy of l
EdF/SEPTEN and J. de Toni of EdF/CNEPE. The intent of the development of
the code was to provide a centralized method for predicting and controlling flow
accelerated corrosion at the 54 nu: lear plants operated by EdF. The main
objectives of the code are the removal of the likelihood of a pipe rupture and the l
reduction of maintenance program costs. The code is currently used by EdF to l
diagnose the state of piping in the secondary system of a plant, assess component i
lifetimes, prepare inspection campaigns, optimize replacement and repair ;
l
strategies, and document analysis,
The code provides a database function for the codes and standards used in the
'
plant construction, an inventory of the lines and elements, plant operating history,
plant chemistry history, and inspection results. Algorithms used to predict flow l
accelerated corrosion of components are based principally on a modified form of ;
the Sanchez Caldera model2 a supported by testing" performed in the CIROCO l
test loop run by EdF and feedback from operating plants. The basic predictive
~'
algorithm used in the BRT-CICERO code to determine the rate of FAC is as
follows: i
'
FAC = f(Cr) * f(6) * (C,* - C.,) (1)
,
g, l
< 0.5 * ( k + D )i
Where:
f(Cr) Alloy Composition Factor
f(0) Oxide Porosity Factor
C,y Equilibrium Soluble Ferrous Ion Concentration
C., Bulk Soluble Ferrous Ion Concentration
k Mass Transfer Coefficient
6
-
Oxide Layer Diffusion Factor
D
,
The Alloy Composition Factor is a function of the Chromium, Molybdenum, and
Copper concentrations in the material ofinterest. BRT-CICERO assumes an
average alloy composition if no specific information is available. The average
values are based on extensive testing by EdF of a large number of heats of carbon
steel material. EdF also tests alloy composition of each component inspected as a
. . .
TR-97-009 Fort Calhoun FAC Assessment of Extraction Steam Line BRT-Cicero Code . 2
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Tetra Engineenng Group, Inc.
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matter of policy. This removes a considerable uncertainty in the FAC rate i
1
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predictions which would otherwise be present if the alloy composition is
unknown.
The Oxide Composition Factor and the Ferrous Ion Concentrations are functions
of pH and temperature. The Mass Transfer Coefficient 's a function of velocity
and the oxide Layer Diffusion Factor is a function of temperature.
Equation 1 applies to straight pipes. For elbows, tees, aad other geometric
,
discontinuities a geometry factor is applied. This geometry factor is a function of
the Sherwood number and accounts for the increased mass transfer as a result of
the discontinuity.
5
The BRT-CICERO code is used by first constructing a plant database. The plant
database consists of all susceptible lines modeled from isometric drawings plus j
data such as construction code, design conditions, and operating conditions. {
Additional information which must be entered includes pipe material properties,
nominal wall thickness plus tolerances, plant operating history, water chemistry ,
history, etc. Structural margins are then determined in order to quantify the
available wall for acceptable FAC degradation. Wear calculations are tlien
performed on all components and predicted wall thickness with associated j
, uncertainties determined for each component.
l
The code is used to assist in the selection of camponents for inspection. l
Components can be classified in terms of the margin between projected thickness
and design thickness, the wear rate, or the time to minimum required wall
thickness. The code can then be used to determine the minimum inspection
frequency for the component.
When a component is inspected the 'UT information is entered into the code md
measured wear determined. Projections of the future wall thickness are based on
the observed wall thickness.
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TR 97-009 Fort Calhoun FAC Assessment of Extraction Steam Line BRT-Cicero Code . 3 !
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Fort Calhoun 4th Stage Extraction Steam
Line
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The BRT-CICERO code was used to assess the rate of FAC in the failed section
of the Fort Calhoun 4* stage extraction steam line using the data provide in
appendix A. Only the section of the line from the nozzle to the first tee was
considered. The following assumptions were made:
1. The Unit was assumed to be at 100% power for the entire 145000 operating
hours.
2. Chemistry was assumed constant at a pH of 9.44,
'
3. Fluid conditions in the line were:
Enthalpy 2.64x10' kjoule/kg
Flow 36.9 kg/see
Pressure 18.961 bar
4. Chromium content of the failed sweep elbow was 0.068%.
.
5. The radius of the sweep elbow was 1.5 m.
Based on the above input assumptions, the BRT-CICERO code projects a wall
loss of 10.9 mm or 0.429 inches for the 145000 operating period'. This compares
with the range of possible initial wall thickness of the component of 0.328 to
0.422 inches. The range ofinitial wall thickness reflects the nominal wall
thickness of the component *12.5% for the as procured tolerance.
The wear projected by the BRT-CICERO code is conservative to the observed
wall loss by anywhere from 0.057 to 0.151 inches depending on the actual initial
thickness of the component and assuming the rupture occurred with 0.050 inches
of wall remaining. This is reasonably good agreement given the assumptions
regarding operating conditions and chemistry.
1
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TR-97-009 Fort Calhoun FAC Assessment of Extraction Steam LineFort Calhoun 4th Stage Extraction Steam Line = 4
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! Comparison of BRT-CICERO to
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CHECWORKS l
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The CHECWORKS model of the Fort Calhoun 4* stage extraction line was not
- available for review, therefore a detailed comparison of the CHECWORKS and 1
BRT-CICERO models could not be performed. However, some observations can l
be made with regard to the general calculational approaches. For the purposes of l
this report, only observations pertinent to the determination of the 4* stage I
extraction line failure are provided.
There are three main differences in the approaches used by the two codes which
may have an effect on the prediction of wear in the 4* stage extraction line. These
differences are related to the use of a line correction factor, the treatment of alloy
content, and prediction uncertainties.
CHECWORKS employs an adjustment factor termed the "Line Correction j
Factor"in the " pass 2" wear calculation. This correction factor is intended to l
adjust the predicted wear rate of all components in a line by considering the
'
differences between the predicted wear and the measured wear for the components ,
'
on that line that were inspected. This has the effect of adjusting the predicted l
wear of one component based on the measured wear of a different component, l
essentially broadening the use oflimited inspection data. This is useful provided I
that all components in the line are behaving in a similar fashion and the inspected
components contributing to the line correction factor are carefully selected.
The BRT-CICERO code does not employ a line correction factor. Inspection data
from one component is not :xtrapolated to other components. Inspection data is
used to adjust the predicted wear for that particular component only.
Both codes use a default value for alloy content of a component when no
information is available. CHECWORKS assumes a alloy content value of 0.0%
for carbon steel components, while BRT-CICERO uses an average value. The
0.0% value assumed by CHECWORKS would be conservative when calculating
the wear rate of an individual component. However, when coupled with the use
of a line correction factor, a potentially non-conservative scenario may occur. A
non-conservative prediction of wear could occur when a limited number of
examinations are performed on a line and the components selected happen to have
unmeasured alloy contents greater than the component ofinterest. The inspected
components would have lower wear rates due to the alloy effect. When the line
correction factor is used and wear for the line is determined, the projected wear
rate for the low alloy content component may be non-conservative.
.a
TR-97-009 Fort Calhoun FAC Assessment of Extraction Steam LineComparison of BRT-CICERO to CHECWORKS . 5
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bN ras engsneenne aroup. Inc.
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Uncertainty in the prediction of wear is explicitly addressed on an individual
m component basis in the BRT-CICERO code but not in the CHECWORKS code.
THE BRT-CICERO output provides an average wear value plus upper and lower .
bound values. The uncertainty in the predicted wall thickness is based on the
uncertainty in the initial wall thickness, which is typically 112.5%, plus
uncertainty in the alloy composition, uncertainty in UT measurements, and
uncertainty in the wear calculation. If a baseline inspection is performed or once
the comp'onent is inspected during service, the uncertainty in the initial thickness
is eliminated. Thickness projections and associated uncertainties are "re-zeroed" j
from the inspected wall thickness measurement. This can not be done easily in l
l
CHECWORKS for components that have no initial baseline and that are inspected
after an initial operating period. Instead, a nominal wall thickness is assumed and
wear is emnulative c,ver the life of the component.
Similarly, the contribution of the alloy uncertainty can be eliminated in the
BRT-CICERO code by the performance of an in-situ alloy analysis.
CHECWORKS also has the capability to record and apply the allow composition j
should the composition of a component be determined. It does not, however,
'
explicitly address the uncertainty of unknown alloy compositions on a component
basis.
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TR-97-009 Fort Calhoun FAC Assessment of Extraction Steam LineComparison of BRT-CICERO to CHECWORKS e 6
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- Conclusion
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The BRT: CICERO code was used to model the failed section of the Fort Calhoun
! 4* stage extraction steam line. The predicted wall thinning from the code was
8
conservative to the observed degradation but still within reasonable agreement.
>
More important is that the predicted time to failure for this component would have
l been less than the observed time to failure.
I It should be noted that the exact measured chromium content was used in the
- determination of the wear for this component. This in rormation was not available
m prior to the rupture. The value of 0.068% is somewhat less than an average of
approximately 0.16W and may have contributed to the high wear rate. If an
l average value for chromium was used in the BRT-CICERO code a somewhat less
conservative wall loss would be predicted. This analysis was not done, but it is
- likely that the code would have projected a failure of this component in time to 1
avoid the actual rupture. !
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TR-97-009 Foot Calhoun FAC Assessment of Extraction Steam Line Conclusion * 7
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- References
I
!
!
l
]' l'. Bouchacourt, M.,"BRT-CICERO 'A Software for Controlling Flow I
- Accelerated Corrosion' - User Manual," Revision A, EdF, Lyon, France, June i
1995. !
2. Sanchez Caldera, L. E., "The Mechanism of Corrosion-Erosion in Steam
j. Extraction Lines of Power Stations," Ph.D. Thesis, Massachusetts Institute of
Technology,1984.
3. Cragnolino. G., Czajkowski, C., Shack, W. J., " Review of Erosion-Corrosion j
j in Single Phase Flows," NUREG/CR-5156, April 1988 !
l
i 4. Ducreux, J., "The Influence of Flow Velocity on the Corrosion-Erosion of ,
Carbon Steel in Pressurized Water," Water Chemistry 3, BNES, Lond'on,
l 1983.
I
5. Berge, P, Khan, F.," Corrosion-Erosion Des Aciers Dans L' Eau et la Vapeur
'
Humide," R6 sums et conclusion de la reunion de sp6cialistes, Mai 1982.
i
,rs 6. M. Bouchacourt E-Mail to F. Anderson," Transmittal of BRT-CICERO code !
I
results", June 2,1997.
]
i 7. Jonas, O., " Erosion-Corrosion of PWR Feedwater Piping Survey of l
- Experience, Design, Water Chemistry, and Materials," NUREG/CR-5149,
- March 1988.
4
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TR-97-009 Fort Calhoun FAC Assessment of Extraction Steam Line References . 8
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OEP7blicP7,verD$ ~
444 South 16th Street Mall
Omaha NE 68102-2247
l
June 4. 1997 l
LIC-97-0087
i
U.S. Nuclear Regulatory Commission
Attn: Document Control Desk '
Mail Station P1-137
Washington. D.C. 20555-0001
References: 1. Docket No. 50-285
2. LER-97-003 Manual Reactor Trip Due to a Steam Line. Rupture
l
SUBJECT: Assessments Related to the Extraction Steam Line Rupture of April
21, 1997
l
'
As committed in the May 5. 1997 Public Meeting, please find attached the
assessments completed in response to the extraction steam line rupture of )
April 21. 1997. These documents contain Omaha Public Power District's (OPPD)
, internal findings and recommendations concerning the Extraction Steam Line I
Rupture event that occurred at Fort Calhoun Station (FCS) on April 21, 1997. !
OPPD's corrective actions for this event are listed in LER-97-003. For the l
purpose of providing additional detail to the NRC the corrective actions in !
LER-97-003 are expanded upon in Attachment 1 of this correspondence. However. '
these specific actions may change as OPPD continues to review and improve its
program and are not meant as additional commitments.
At this time, the failure analysis of the ruptured elbow has not been
received. This item will be sent at a later date.
Please contact me if you have any questions.
Sincerely,
y&
S. K. Gambhir
Division Manager
Engineering and Operations Support
v
c5.5124 Employment with Equal Opportunity
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Attachments 1. Additional Information on Commitments to the NRC for
,
Co~rrective Actions Listed in LER-97-003
2. Fort Calhoun Station Root Cause and Generic Implications '
Report Fourth Stage Steam Extraction Line Rupture CR
, 199700445 Revision 0
3. Damage Assessment Report for the Break in the Extraction !
j Steam Line Revision 0. May 3, 1997
' ,
4. Fort Calhoun Station Erosion / Corrosion Program Assessment !
Report, dated May 2. 1997
i 5. Fort Calhoun Station Self Assessment Erosion / Corrosion
Program Team Findings, dated May 6. 1997
SKG/ddd
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j c: Winston & Strawn
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E. W. Merschoff, NRC Regional Administrator. Region IV
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J. L. Shackelford. Senior Reactor Analyst. DRS i
l L. R. Wharton. NRC Project Manager .
l
W. C. Walker. NRC Senior Resident Inspector
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Attachment 1 -
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l Additonal information on Corrective Actions
! Listed in LER-97-003
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Attachment 1 -
b
Additional Information on Corrective Actions Listed in LER-97-003
)
! In LER-97-03 OPPD committed to " Revise the Erosion / Corrosion Program Plan.
- controlling procedures and modules to be consistent with industry standards.
! This revision will include upgrade of the implementing procedures to be
consistent with industry standards (e.g. NSAC 202L. Rev.1), development of
- susceptibility documentation and requirements for use of current industry 1
i experience. This will be completed by the beginning of the 1998 Refueling i
j Outage." This commitment will address the following issues identified in the l
- self assessment
l 1. Procedures should include more specific guidance on how Outage
i inspection locations ~are chosen.
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i 2. Measured wear determination process should incorporate the following
- industry practices
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j a. Use of accepted practices to determine lifetime component wear
j (circumferential band, moving blanket, point to point).
i
l b. Clarify the use of engineering judgment relative to wear
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determinations.
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c. Process for incorporating measured wear into CHECWORKS models.
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- 3. Sample expansion process should be revised to align it with industry
i standards. Specific changes include:
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i a. Clarify wording for small bore piping.
l b. Add requirement for inspecting upstream of expanders / expanding
2
elbows.
c. Clarify that pressure / temperature exemption only applies to raw
water systems.
d. Clarify that expansion is to parallel components in each train.
~
e. Define the terms " component" and " highest wearing".
7 Specify highest wearing components in the same train.
4. A document is needed to describe and control the identification of
susceptible systems.
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susceptible systems. ,
3 6. Documentation should be provided when grid refinement.or scanning is
performed when significant erosion / corrosion is found.
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7. The inspection data evaluation for components with PASS 2 CHECWORKS !
analysis should consider current predicted wear rates. !
8. The program should employ verification of many elements and a formal
l1 process for changing program elements needs to be established.
(Examples: CHECWORKS model changes. Erosion / Corrosion Program General
Information Table. Erosion / Corrosion Program Technical Data Review.) ;
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Also in LER-97-03 OPPD committed to " Revise and verify the Fort Calhoun
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CHECWORKS models consistent with industry standards by December 31. 1997."
This commitment will address the following issues identified in the self
4 assessment:
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1. Current plant CHECWORKS models need to be verified.
2. Inspection data from 1995 and 1996 outages needs to be incorporated into
j CHECWORKS models consistent with industry practice.
- A 3. The plant CHECWORKS models need to be updated and controls put in place
to document changes.
-
In addit 1Bn OPPD plans to conduct a follow-up self assessment of the
. erosion / corrosion program following the next refueling outage to evaluate the
effectiveness of program enhancements. .
$ During the implementation of our corrective actions OPPD will review and
j incorporate, as appropriate, the following recommendations of the self
assessment team:
1. Program Basis Document should be updated to:
a) Eliminate duplication.
b) Remove unnecessary detail.
c) Make Program Basis Document and inspection procedure consistent.
2. Program Basis Document should describe how susceptible systems are
dispositioned with respect to analysis.
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- 3. Program Basis Document should be updated to enhance communication
l responsibilities between Operations and Maintenance regarding feedback
j to Erosion / Corrosion Engineer.
4. Guidance for documenting rationale for inspecting a specific location
should be provided.
5. The inspection data form should be enhanced to address the following:
a) Directions for the use of this form.
b) Direction for what to do when measured minimum wall thickness is i
inconsistent with nominal wall thickness. !
c) Direction on what to do when previous thickness is not available
and nominal wall thickness is not used. !
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d) Clarify the step " List expansion of test sites not previously
evaluated." -
6. Typographical errors in the Program Basis Document should be corrected. l
7. Typographical errors and inconsistencies in the inspection procedure
should be corrected.
m
8. The highest allowable value of maximum allowable stress (SE) should be
used to eliminate unnecessary conservatism and ensure consistency with
CHECWORKS. I
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9. Program documents should be revised to proceduralize the following: .
a) Trending of inspection results.
b) Qualitative evaluation of inspection data.
c) Evaluation of data to ensure thinning is bounded.
10. The acceptance criteria (Design Minimum Wall) being used for inspection
data evaluations should be reviewed to ensure that OPPD applicable code
requirements are met.
.
11. The grid size on 6" components should be reduced to comply with
recommendations in NSAC 202L.
12. A clear separation in Erosion / Corrosion Program documentation between
Flow Accelerated Corrosion (FAC) and other wall degradation mechanisms
(such as raw water corrosion) should be provided. .
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13. The guidance of NSAC 202L should be employed to address susceptible
piping that is not suitable for modeling.
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14. Complete CHECWORKS models of susceptible piping that is suitable for l
modeling should be developed.
15. The isometric-drawings identifying CHECWORKS component identifiers are
vital tools. A set of these drawings should be placed in retrievable
storage and a second set should be used as a working copy.
16. Sample expansions should not rely excessively on older inspections and .
should aggressively seek to ensure thinning is bounded. l
17. Sample expansion on tee branches need to be performed on the train ,
containing the branch. '
18. The inspection data evaluation process should address how to handle ,
components with readings greater than nominal wall thickness. -
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19. Any exceptions to the grid procedures should be noted on the layout
diagram provided in the outage summary notebook.
20. The CHECWORKS Program should be used to perform inspection data
m evaluation.
21. Each inspection data package should include a printout showing the
inspection data matrix.
22. Although it appears that informal communication does exist between .
various departments and the Erosion / Corrosion Engineer the
Erosion / Corrosion Engineer should perform a review of emergent KdRs via
the Daily Emergent list. Review of this list should give a heads up to
any developing system abnormalities.
23. The closure review of configuration change and maintenance documents
should be strengthened to identify any issue of concern to the
Erosion / Corrosion Engineer. '
l 24. The Outage Scope Change / Addition Request form should be revised to
ensure that requests for deletions and additions to outages are properly
evaluated for Erosion /Cerrosion scope.
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l 25. Feedwater iron transport information should be added to the Seconday
Chemistry Monthly Summary Report.
- 26. OPPD is a member of the CHECWORKS Users Group (CHUG). but is not an
4
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active participant. FAC personnel, especially the Erosion / Corrosion '
Engineer, should attend the CHUG meetings. These meetings are held
twice a year and cover current Erosion / Corrosion technical issues as
well as a forum for discussing plant experiences.
27. OPPD should participate in the CHUG Plant Experience Database to ensure
Erosion / Corrosion staff obtains future updates to this important
industry experience database. _
28. As a one nuclear unit utility, it is recommended that OPPD consider
joining with a group of other similar plants at other utilities to form
a peer group to share experience and peer assistance. I
29. A program to provide flow accelerated corrosion sensitivity training to l
applicable plant staff beyond Erosion / Corrosion personnel should be
considered. This will help to ensure that plant conditions that may
affect flow accelerated corrosion are communicated to the 4
Erosion / Corrosion Engineer and incorporated into the Program.
. .
30. Use of resistant materials and systematic replacements should be
i
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considered.
31. The program should incorporate management involvement in important
program elements. (Examples: CHECWORKS models, outage inspection scope.
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Rg outage close-out)
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l Attachment 2
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l Fort Calhoun Station Root Cause
l and Generic Implications Report
Fourth Stage Steam Extraction Line Rupture
4
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CR 199700445 Revision 0
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, FORT CALHOUN STATION .
ROOT CAUSE AND GENERIC IMPLICATIONS REPORT
FOURTH STAGE STEAM EXTRACTION LINE RUPTURE
CR 199700445
PRC RECOMMENDS
REVISION 0
i APPROVAL'
,
SRG-97-026 MY 0 71997
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t>HG MTG.-MINUTpgg
, A. R. Patel, Lead Evaluator
Date
[. R. Geschw nder, Evaluator
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Date
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W, 4~Y7
fK. G' asper, P/er Review Team Member - CR Owner VD '
' ate
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e 1 4] G~/5/97
. L. Skiles, Peer Review Team Member
.. .
bate
R 4. M
R. L. JaIvorski, Peer Review Team Member
- /s*/r' .
Date
/
R. L. Phelps, Peer' Review Team Member
f d'99
Date
b Sf0Cf97
R. L. Andrews, Peer Review Team Member ' Date
%)&
M. T. Sweigart, PeeVReview Team Member - NSRG
s/sh7#
D$te
dukb b
M. Kellams, supeNisor - HPES/RCA
e su, ' skk7 #
Ddte
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! Damage Assessme::t Report.
- for the Break in the Eyiraction Steam Line
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Revision 0, n'4ay 3,1997 -
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DAMAGE ASSESSMENT REPORT .
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FOR THE BREAKIN THE
.
)
EXTRACTION STEAM LINE
..
Revision 0 l
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May 3,1997 .
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R. L. Phelps, P.E. i
Manager - Station Engineering
M. R. Core, P.E. -
,
,. Manager- System Engineering
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Attachment 4 '
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Fort Calhoun Station
- Erosion / Corrosion Program Assessment Report,
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dated May 2,1997
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FORT CALHOUN STATION
-
EROSION / CORROSION PROGRAM
'
ASSESSMENT REPORT
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Mt >7
L P. Hopkins
b' @~
Craig Y%n[r (%P)
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C OS&
Ned Dietrich (DE&S)
e
Gus Undall"(Representinh EPRI)
,
CSM 4r Dw cl A. A.4k .
David Smith '(DPC):
Approved:
%<1A
Me K.'GasperCo-TeamLeader/ 1 'Taylof
. o-Team Leader
.
tek i d Q
ack L. Skiles Sudesh K. Garrbhir
Co-Team Leader * Sponsor
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Attachment 5
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i Fort Calhoun Station Self Assessment
j -
Erosion / Corrosion Program Team Findings,
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(~ j R6 May L. 1997
Fort Calhoun Station SELF ASSESSMENT
Erosion / Corrosion Program Team Findings
Start Up Issues
!
Responsible Corrective Actions Completion:
Group Date
1. Start Up Issues A. Upgrade the susceptibility evaluation to ensure B. Lisowyj A Restart FAC Susceptibility 05/08/97
(Should be the following: R. Aleksick Review was performed to define Complete
addressed prior a) Susceptible systems are covered. D. Rollins the scope of the FAC Closure
to restart from b) Susceptible segments of susceptible systems susceptible piping. As a Memo
current Forced are identified. result the following FC-0019-17
Outage.) c) Operators input is incorporated. additional lines were added to
Section 2.0, F3 d) Current susceptibility criteria are applied. the program: Seal Steam
e) Susceptible segments of susceptible systems (entire system). S/G Blowdown
need to be addressed. (suction / discharge of BD
transfer pumps). Condensate
Provide NRC the analysis and justification for Recirculation (recirc.). Steam
not test. Traps and Drains. Complete
any additional needed
inspections Pre Start-up.
Continue review to include
lines such as small bore.
Section 4.0, F1 B. Review systems to ensure piping and components R. Ruhge Review MW0s. Mods. past 05/05/97
downstream of replaced components have been R. Frakes inspection data to determine Complete
inspected to ensure industry experience has been K. Hyde inspected locat, ion. Perform Closure
addressed. Document report. an inspection not previously Memo EOS-
Followup justification of why exclude in the past completed. MWO 971649 SSE-97-065
to provide to NRC later. (Complete)
Section 4.0. F2 C. Component S-56 appears to have been installed R. Jaworski Inspect 5-56 and documentation 05/08/97
without the required reinforcing pad. K. Woods to determine thickness of Complete
(Documentation is being pursued by OPPD personnel component. Modify if Closure .
that may resolve this issue.) (Prior to Critical) necessary. Memo EOS-
ECN 97-161. CWO 97-037 (Comp..) SSE-97-066
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.) R6 May ' 1997
Fort Calhoun StoCion SELF ASSESSMENT
Erosion / Corrosion Program Team Findings
Start Up Issues
,
'
Responsible Corrective Actions Completion
Group Date
Section 4.0. F3 D. Packages from the 1996 Outage have'not been D. Rollins Review pkg 5-4. S-33. 0-26A. 05/08/97 l
independently reviewed (Examples: S-4. S-33. A. Patel S-38. D-84A. D-213 and other Complete
D-26A. S-38. D-84A. D-213) as of 4/30/97. (Prior pkgs if identified. Closure
to Critical) Memo ,
Section 4.0 F4 E. Components displaying significant wear should be N. Dietrich Re-evaluate-components using 05/09/97
re-evaluated using industry standard techniques. industry techniques. Identify Complete
(Examples: S-73. S-74. S-66 and S-63) needed inspections as needed. Closure
Provide Technical discussion. Memo
Sectior 4.0. F7 F. Data or evaluations could not be found for the D. Rollins Locate documentation and 05/09/97
some 1996 inspection locations. (Examples: 5-57 R. Ruhge include in database. Complete
S-80. 5-92) (Prior to Critical) Closure
Memo EOS-
SSE-97-068
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b' FortCalhounStationSELFASSESSMENT
.i) R6 May '1997
Erosion / Corrosion Program Team Findings !
Start Up Issues
,
,'
Responsible Corrective Actions CompletionI
Group Date' !
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Section 4.0. F9 G. A review of high priority systems (Feedwater. D. Rollins Review the 6 hish priority 05/08/97
Steam Dump and Bypass. Blowdown. Extraction B. Lisowyj systems and identify points Closure
Stean Condensate, and lleater Drains) should be
,
needing inspection. Complete Memo !
performed to ensure locations that industry inspections or verify that FC-0021-97 '
experience has shown to be potentially. inspections have been t
susceptible have been addressed. performed. Complete necessary :
Meeting on how we came up with these system and repairs / replacements as
selection criteria. necessary.
Inspection MWO's:
!
Complete: i
971627(ES-3A). 971629(ES-2E). I
971630(ES-2C). 971632(HD-3A. >
38. 3C). 971649(11D-18).
971674(HD-IH) 971703(11D)
971666(SGB-2C)
Repair NWO's:
Complete: I
971650(HD-3A). 971651(11D-38). !
971652(llD-3C). 971655
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FsrtCr,thouni.a$ ion SELF ASSESSMENT 1 R8 Hi , 997
Erosion / Corrosion Program Team Findings
short Term / tong Term issues
Responsible Corrective Actions CceptetIJn
Group Date
2. Short 1erm issues A. Procedures should include more specific guidance on how B. Lisowyj Provide additional specific guidance
Outage inspection locations are chosen. I 1998
(Should be Procedure for determining outage inspection Refueling
addressed prior to Group locations in the Program Basis Outage e
restart from the ,
Docunent (PD8) and other program
1998 Refueling documents as needed.
Outage.)
Srction 1.0, F1 CID 970567/01
Szction 1.0, F2 s. Measured wear determination process should incorporate the 8. Lisowyl Incorporate industry practices for
following industry practices: 1998
Procedure measured wear determinations in Refueling
a) (Jse of accepted practices to determine lifetime Group appropriate program documents as Outage
comonent wear (circunferential band, moving follows:
blanket, point to point)
a) use of accepted practices to
b) Clarify the use of engineering judgment relative to
determine lifetime component
wear determinations. wear (circumferentist band,
c) Process for incorporating measured wear into moving blanket, point to point)
CHECWORKS models. b) Clarify the use of engineering
judgment relative to wear
determinations. ,
c) Process for incorporating
measured wear into CHECWORKS
models.
CID 970567/02
Section 1.0, F3 C. Sagte expansion process should be revised to align it with 8. Lisowyj Revise the sagte expansion process to
Industry standards. Specific changes include: 1998
be consistent with industry standards Refueling
a) Clarify wording for smatt bore piping. as follows:
b) Add requirement for inspecting upstream of Outage
expanders / expanding elbows,
a) Clarify wording for small bore
piping,
c) Clarify that pressure /teverature exemption only b)
applies to raw water systems. Add requirement for inspecting
upstream of expanders / expanding
d) '
Clarify that expansion is to patattet co m onents in elbows.
each train. c) Clarify that '
e) Define the terms " component" and " highest wearing."
f) Specify highest wearing co monents in the same pressure / temperature exemtion
train.
only applies to raw water
systems,
d) Clarify that expansion is to
parattel components in each
train.
, e) Define the terms "co monent" and
. " highest wearing."
f) Specify highest wearing
components in the same train.
CID 970567/03
.
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i fort Csthounl T,lon SELF ASSESSMENT ,
'
Erosion /Corrostw/>rogram Tsam Findings
Short Term /Long Term Issues
Responsible Corrective Actions Completion
Group Date
-
S2ction ?.0, F1 D. A docunent is needed to describe and control the S. Lisowyj Revise existing documents or deveicp 1998
Identification of susceptible systems. ,
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Procedure new docments to describe and control Refueling
Group the process for the identification of Outage
'
susceptible systems. ,
CID 970567/04 ,
Section 2.0, F2 E. A docunent is needed to describe and control the evaluation B. Lisowyj Devel>ip or revise existing procedures
. 1998
of susceptible systems. Procedure to describe and control the evaluation Refueling
Group lofsusceptiblesystems. Cutage
CID 970567/05
Section 3.0, F1 F. Current plant CHECWORKS models need to be verified. 9. Lisowyj Verify the current CHECWORKS modet. 1998
Refucting
CID 970567/06 Outage
Section 3.0* F2 G. Inspection data from 1995 and 1996 outages needs to be B. Lisowyj Input inspection data from 1995 and Prior to
Incorporated into CHECWORKS models consistent with industry 1996 outages into CHECWORKS n'.odel. 1998
practice. Refueting
CID 970567/07 Outage
Stetton 3.0* F3 H. The plant CHECWORKS models need to be updated and controls B. Lisowyj Ltpdate plant CHECWORKS model and Prior to 1
put in place to doc m ent changes. Procedure revise existing documents or develop 1998
Croup new docments to adninistratively Refueling
contret revisions to CHECWORKS model. Outage
Clu 970567/08
Srction 4.0* F5 3. Docunentation should be provided when grid refinement or B. Lisowyj Revise existing docunents or create 1998
scanning is performed when significant erosion / corrosion is Procedure new documents to require documentation Refueling '
found. Group when grid refinement or scanning is Outage
performed when significant
erosion / corrosion I,s found.
CID 970567/09
Section 4.0' F6 J. The inepection data evaluation for components with PASS 2 B. Liscwyj Revise inspection data evaluation for 1998
CHECWORKS analysis did not consider current predicted wear components with PASS 2 CHECWORKS Refueling
rates. analysis to consider current predicted Outage
wear rates.
.
. CID 970567/10
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Fe:rt C:lhoun ..ttion SELF ASSESSMENT
Erosicn/ Corrosion Program Team Findings
Short Term /Long Term Issues
Responsible Corrective Actions Completioni
Croup Onte
Section 4.0, F8 K. The program does not appear to employ verification of many 8. Lisowyj Revise doctanents or create new 1998
elements and a formal process for changing program elements Procedure documents to strmgthen adsinistrative Refueling
does not appear to exist. (Examples: CHECWORKS model Group control of verifir.ation and changes to Outage i
changes, Erosion / Corrosion Program General Information Table, program elements (Examples:
Erosion / Corrosion Program Technical Data Revleu.) CHECWORKS model changes,
Erosion / Corrosion Program Generat
Information Table, Erosion / Corrosion
Program Technical Data Review.)
CID 970567/11
3. Long Term tstues A. A follow-up assessment should be performed following the next J. Casper Perform a format assessment after 1998 Post 1998
S ction 9.0, F1 refueling outage to evaluate the ef fectiveness of program RF0 to evaluate the effectiveness of Refueling
enhancements program enhancements Outage
CID 970567/12
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Enclosure 3
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Fort Calhoun Station
NRC Handout
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- PREDECISIONAL ENFORCEMENT CONFERENCE AGENDA
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, CONFERENCE WITH OMAHA PUBLIC POWER DISTRICT
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July 21,1997
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NRC REGION IV, ARLINGTON, TEXAS
,
4
1. ' INTRODUCTIONS / OPENING REMARKS - Ellis Merschoff, Regional Administrator
'
2. ENFORCEMENT PROCESS Michael Vasquez, Enforcement Specialist
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3. APPARENT VIOLATIONS & REGULATORY CONCERNS - Dwight Chamberlain,
j. Deputy Director, Division of Reactor Safety
1
i 4. LICENSEE PRESENTATION -
!
{ 5. BREAK (10-MINUTE NRC CAUCUS IF NECESSARY)
i
j- 6. RESUMPTION OF CONFERENCE
7. CLOSING REMARKS - LICENSEE
8. CLOSING REMARKS - Ellis Merschoff, Regional Administrator
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[ APPARENT VIOLATION *
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! PREDECISIONAL ENFORCEMENT CONFERENCE
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OMAHA PUBLIC POWER DISTRICT l
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[ JULY 21,1997]
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- NOTE: THE APPARENT VIOLA TION DISCUSSED A T THIS PREDECISIONAL
ENFORCEMENT CONFERENCE IS SUBJECT TO FURTHER REVIEW AND MA Y BE REVISED
- PRIOR TO ANY RESULTING ENFORCEMENT ACTION.
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APPARENT VIOLATION
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1.
10 CFR 50.65(a)(1) states, in part, that each holder of a license to operate a nuclear plant
shall monitor the performance of structures, systems, or components, against licensee-
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established goals, in a manner sufficient to provide reasonable assurance that such j
structures, systems and components, as defined in paragraph (b), are capable of fulfilling
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their intended functions. Such goals shall be established commensurate with safety and, '
where practical, take into account industry-wide operating experience.
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10 CFR 50.65(b) states, in part, that the scope of the monitoring program specified in I
paragraph (a)(1) shallinclude safety related and nonsafety related structures, systems, and !
components as follows: (2) Nonsafety related structures, systems, or components: (iii) l
- Whose failure could cause a reactor scram or actuation of a safety-related system, i
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10 CFR 50.65(a)(2) states, in part, that monitoring as specified in paragraph (a)(1) is not
required where it has been demonstrated that the performance or condition of a structure,
system or component is being effectively controlled through the performance of
appropriate preventive maintenance, such that the structure, system or component remains ,
capable of performing its intended function. I
Contrary to the above, as of April 21, '.997, for certain nonsafety related structures within
the scope of this rule, the licensee had neither monitored the performance of these
structures against licensee-established goals, nor demonstrated that the performance or
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condition of these structures was being effectively controlled through appropriate
preventive maintenance such that the structures remained capable of performing their I
intended functions. Specifically, the large radius piping elbows of the fourth stage
extraction steam system, sixth stage extraction steam system piping and other piping in
the heater drains system were neither monitored nor effectively controllad through j
preventive maintenance such that these piping locations remained capable of performing i
their intended function. This was evidenced by: 1) the second downstream large radius
piping elbow in the fourth stage extraction steam system failed catastrophically on April l
21,1997, resulting in a plant transient; and 2) the following piping structures were l
subsequently determined to be below minimum wall thickness: a) the furthest downstream
large radius piping elbow in the fourth stage extraction steam system line (S-32); b) a sixth
stage extraction steam system " pup" piece (S-54); and c) three parallel lines in the heater
drains system (D-95).
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THIS APPARENT VIOLA TION IS SUBJECT TO FURTHER REVIEW AND MA Y
BE REVISED