IR 05000456/1993021
| ML20058H385 | |
| Person / Time | |
|---|---|
| Site: | Braidwood  |
| Issue date: | 12/03/1993 |
| From: | Farber M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20058H367 | List: |
| References | |
| 50-456-93-21, 50-457-93-21, NUDOCS 9312130062 | |
| Download: ML20058H385 (13) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Reports No. 50-456/93021(DRP); 50-457/93021(DRP)
Docket Nos. 50-456; 50-457 Licenses No. NPF-72; NPF-77 Licensee:
Commonwealth Edison Company Opus West III 1400 Opus Place Downers Grove, IL 60515 facility Name:
Braidwood Station, Units I and 2 Inspection At:
Braidwood Site, Braceville, Illinois Inspection Conducted:
September 11 through November 19, 1993 Inspectors:
S. G. Du Pont E. R. Duncan R. B. Landsman
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I Approved By: M.J.Farbeg(Chief
/ /Date Reactor Projects Section lA Inspection Summary lpspection from September 11 through November 19. 1993 (Reports No. 50-456/93021(DRP): 50-457/93021(DRP))
Areas Inspected:
Routine, unannounced safety inspection by the resident inspectors of licensee action on previously identified items; licensee event report review; operational safety verification; monthly maintenance observation; monthly surveillance observation; engineering and technical support; plant support,-11 2500/28; and report review and meetings.
Results:
No violations were identified.
Onerations Operations during this inspection period were good. Operators responded effectively during three events (Paragraph 4).
Operations were more conservative than technical specifications in
response to the October 23, 1993 1C steam generator tube leak.
An opportunity to demonstrate additional conservative measures by
reducing power early during the event on October 23, 1993 was missed.
9312130062 931203 PDR ADDCK 05000456 G.
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Plant Support Good teamwork was demonstrated during three events.
Actual total accumulated dose during the forced outage was significantly
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less than planned due to preparations and teamwork.
j Accumulated dose was reduced during the 1 spike associated with the
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333 October 3, 1993 Unit 2 trip due to preparation and teamwork.
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t A N0ED was requested to restart Unit I after the October 23, 1993 steam
generator tube leak.
The licensee did not recognize that Technical Specification 4.4.5.2 had
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been entered.
lhis was due to the fact that the LC0 associated with
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3.4.5 was not exceeded. The Office of Nuclear Reactor Regulation prompted the licensee to request enforcement discretion.
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Enaineerina and Technical Support
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Good management involvement was evident during the October 23, 1993
forced outage.
Engineering provided good support during the October 23, 1993 forced
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outage.
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DETAILS I
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Persons Contacted
- l Commonwealth Edison Company (CECO)
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i 5. Berg, Vice President J. Achterberg. Executive Assistant
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- K. L. Kofron, Station Manager l
T. Schuster, Acting Support Services Director i
- A. Haeger, Regulatory Assurance Supervisor
- R. Kerr, Engineering and Construction Manager
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- D. E. Cooper, Operations Manager i
G. E. Groth, Maintenance Superintendent
- R. Byers, Work Control Superintendent l
- D. Miller, Technical Services Superintendent i
K. Bartes,-Quality Verification Superintendent o
- A. Checca, System Engineering Supervisor
S. Roth, Security Supervisor 1'
T. Pendergast, Regulatory Assurance
- L. Alexander, Lead Chemist
- S. Butler, Senior Quality Verification Inspector f
- Denotes those attending the exit interview conducted on November 19, 1993.
The inspectors also interviewed several other licensee employees.
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2.
Licensee Action on Previously identified items (92701. 92702)
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a.
Unresolved items
i (Closed) 456/91014-01: 457/91012-01 and 456/91014-02: 457/9101,
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02:
Safety-related check valves smaller than two inches were not
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included in the Braidwood check valve program.
The licensee
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verified that check valves required to perform specific functions
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in shutting down the reactor to cold shutdown or in mitigating the
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consequences of an accident are included in the ASME Section XI
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IST program required by 10 CFR 50.55(a). Additionally, the check i
valve program is separate and independent of 10 CFR 50.55(a)
l requirements. Check valves less than two inches are included in i
the check valve program based on reliability studies.
Based on j
the selection criteria of the check valve program, one of the I
check valves identified in the inspection report was added to the-
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program.
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Since the check valve program is independent of 10 CFR 50.55(a)
I and the reliability criteria included only one of the questioned
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check valves, these items are considered to be closed.
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Violations j
(Closed) 456/92025-01: 457/92025-01:
Violation of 10 CFR 50, i
Appendix B, on failure to take corrective action to a 1990 event
report. The licensee conducted a review of all other event reports and verified that all other required actions were completed.
The inspector also independently reviewed a sample of
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event reports between 1988 and 1991 and verified that all required actions were completed.
l Based upon the above reviews and the lack of any other existing example, these items are considered to be closed.
No violations or deviations were identified.
3.
Licensee Event Report (LER) Review (92700)
i LERs were reviewed and closed based on the following criteria:
i Reportability requirements were met.
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Immediate corrective actions were accomplished.
- Corrective actions to prevent recurrence have been or will be
initiated per technical specifications.
(Closed):
456/93005 l
457/93004
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r 457/93005 457/93007
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No violations or deviations were identified.
4.
Operationa'
afety Verification (71707)
The inspectors verified that the facility was being operated in conformance with the licenses and regulatory requirements and that the-licensee's management control system was effectively carrying out its responsibilities for safe operation.
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No violations or deviations were identified.
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During this reporting period, several events occurred. A Unit 2 trip _
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occurred on October 3 and Unit 1 entered a forced shutdown on October 23 due to a primary-to-secondary steam generator tube leak.
The following activities were reviewed or observed during this period.
1 October 3, 1993 Unit 2 Trip
Inadvertent Trip of Bus 243
October 23, 1993 Unit 1 Shutdown J
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Operator's Response
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Management's Involvement j
Coordination of Activities by Plant Staff t
Conclusion
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Unit 2 tripped on October 3, 1993, due to a low steam generator level condition. The cause of the low level condition was the result of the 2D feedwater regulating valve failing closed. All safety systems
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responded as designed and the transient was easily mitigated.
Unit 2 has an operating history with a known leaking fuel element. The
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licensee entered their response procedures and began an increased monitoring frequency for Iodine-131 (13u).
The licensee discovered that the root cause of the regulating valve failure was a tear in the valve positioner bellows.
The licensee inspected the bellows on the remaining regulating valves on Units 1
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and 2 and did not find any additional degraded bellows. Additionally,
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information pertaining to the failure mechanism and lessons-learned were
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provided to the Byron Station technical staff. Management also decided
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to replace all bellows to avoid a recurrent failure.
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On October 12, 1993, an equipment operator inadvertently deenergized Bus 243.
The operator was assigned the task of taking the Unit 2 Main Power Transformer #2 West out-of-service (005) to allow preventive maintenance l
of adding oil to a transformer bushing.
The 00S involved pulling fuses for the secondary potential transformer.
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The operator removed the fuses, which appeared to be those required by the 00S.
However, the pulled fuses were those that deenergized the Bus 243 relaying and metering functions, resulting in the deenergizing of the bus.
Since Unit 2 was in hot shutdown following the October 3 trip, none of the affected equipment on Bus 243 had any safety or operational
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functions and only the secondary plant was affected.
The bus was
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quickly returned to service.
The licensee conducted an investigation into the event to determine the f
root cause and to develop appropriate corrective actions and lessons-
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learned.
The root cause was determined to be inadequate written l
communications associated with the 00S.
Additionally, the licensee identified weak work practices that contributed to.the event.
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l The written instructions associated with the 00S were inadequate.
The j
00S required pulling fuses for " Bus 243 UAT POT S" on Bus 243 cubicle 07.
Bi ; 243 has two sets of' fuses, with actual nomenclature of
" BUS 243 PT SEL 6A FU7" and "UAT FEED PT SEC 6A FU8."
The nomenclature was for Bus 243 potential (PT) secondary (SEC) fuse number FU7 and unit j
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auxiliary transformer (UAT) potential secondary fuse number FU8. As a result of the investigation, the licensee changed the standard 00S j
nomenclature usage to match the actual infield usage.
The licensee also developed and implemented actions to improve work i
practices associated with the 005 process. The licensee's investigation i
determined that the specific procedure for isolating the Unit 2 main j
transformer was not required by the 00S and the operator did not perform
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an additional verification by questioning the wording of the 00S
instructions.
The 005 process was strengthened by requiring use of l
existing isolation procedures.
Unit I was shutdown on October 23, 1993 because of a primary-to-l secondary leak on the IC steam generator.
Early on October 23, the unit
operators were alerted to the possibility of a steam generator tube leak by various radiation monitors approaching their alert setpoints.
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The operators are trained to recognize increasing radiation levels on the main steam lines, steam generator blowdown lines, and the condenser
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air ejector exhaust line as an indicator of an existing or increasing
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primary-to-secondary leak through the steam generator tubes. Since the
steam generator tubes are a primary boundary, actions are required to
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verify and to isolate the primary leak.
Technical specifications have a-j 500 gallon per day (gpd) limit which requires immediate shutdown of the
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plant.
t The operations staff immediately requested steam generator (SG) samples to determine the affected SG and the leak rate. The initial "short t
sample" determined that the "C" SG was the affected SG. A "long" sample
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subsequently deterniined the leak to be between 200 and 240 gpd by Iodine
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and Sodium analysis methods.
A portable Nitrogen-16 (N ) detector was a
also connected to the "C" SG steam line. The Na detector indicated that the leak rate was approximately 170 gpd.
The N detector is
a considered to be a more accurate method of determining leak rates.
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Additionally, the N detector provides the ability to monitor real time-a trends compat to SG samples which require several hours to provide
calculated leok rate.
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Licensee management was briefed by the operating staff and an
administrative limit of 300 gpd was established to ensure that the
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technical specific ion limit of 500 gpd was not exceeded. Also, the j
sampling frequency was increased to twice that required by technical l
specifications to ensure more timely assessment of leak rate trends.
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These assessments were assisted by the N detector.
a The leak rate remained stable for the first eight or nine hours of the event.
A subsequent increase in leak rate was detected and the administrative limit of 300 gpd was exceeded. Management directed the
commencement of a controlled shutdown at 1 Megawatt / electrical per l
minute (5%/ hour).
The licensee determined that a shutdown rate of 5%
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per hour would create less transient stress on the leaking tube compared
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aggravating the leak or creating a tube rupture condition.
The shutdown was delayed about one hour for steam generator chemistry concerns cnd to complete the required shutdown calculations.
Throughout the shutdown to mode 5 (cold shutdown), the leak rate remained stable at about 300 gpd. The unit achieved cold shutdown, the primary was
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depressurized on October 24, and the leak stopped.
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The operator's response to the events was good.
Operator's actions associated with the October 3, 1993 Unit 2 trip were effective in mitigating the transient. Operations was also prompt in addressing the i
expected Im spike from the known leaking fuel element by requesting -
increased monitoring.
Plant personnel were promptly notified on increased radiation levels within specific areas of the auxiliary building, j
Prompt response and recognition of the inadvertent deenergizing of Bus
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243 on October 12 by the operating staff also mitigated a transient on
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the secondary plant due to loss of equipment. The operators were' quick to recognize the effects of Bus 243 deenergizing and restored feedwater i
to the steam generators thus avoiding a temperature transient across the
The operators were also quick to recognize the' emergence of a steam generator tube leak on October 23 before radiation monitors reached l
alarm setpoints.
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l Braidwood management's involvement was evident durino +ba events.
Management demonstrated conservative and safety-based,s _ 1erations in their decisions associated with the events.
Management en. ed that appropriate actions were initiated pertaining to the known leaking fuel
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element during the recovery from the October 3 Unit trip.
l Management considered the risk of a tube rupture during the October 23 shutdown and selected a conservative shutdown rate of 5% per hour. A good approach for safety was taken by initiating a-controlled shutdown more conservative than the requirements of the technical specification.
Industry experience has demonstrated that reducing power to about 50%'
with steam generator tube leaks will reduce the probability of creating a tube rupture.
The licensee took the conservative approach of initiating a shutdown to mode 5 instead of reducing power to 50%,
however, a more conservative action would have been-to begin reducing power to 50% when the magnitude of the. leak was initially determined.
Management's decision to replace all feedwater regulating valve positioner bellows after the October 3 Unit 2 trip was conservative.
During the events, good coordination of the various departments was demonstrated. The October 23 trip and recovery demonstrated good teamwork between operations, chemistry, and radiation protection departments in addressing the effects of the known leaking fuel
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elements.
The radiation protection department performed prompt and frequent surveys of the auxiliary building to ensure that dose posting
was accurate and to prevent unnecessary dose accumulation. The i
radiation protection and operations department previous planning and development of contingencies were evident by the results of minimal increases of station accumulated dose.
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During the activities associated with the shutdown to repair the Uait 1
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steam generator tube leak, the teamwork between the operations, chemistry, radiation protection, maintenance, and engineering
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departments was also evident. Throughout these outage, good industrial l
safety practices were evident with no safety events or incidents.
The
team promptly developed and implemented a forced outage plan, which
included coordinating the aspects of radiation protection, industrial i
safety, mechanical removal of SG shielding and insulation of
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troubleshooting equipment. The team also demonstrated flexibility by expanding their troubleshooting efforts as data was evaluated. The
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efforts expanded to include a 100% end-to-end eddy current-testing of
the IC SG using Bobbin Coil methods and a large portion of the freespan space of the U-Tubes using Rotating Pancake Coil (RPC) method. The
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expansion of these efforts increased the outage duration from an i
expected 13 to 21 days. The initial planned accumulated dose for the 21
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day outage was 14.2 person-rem, well below the planned dose for a 13 day
outage.
i The inspectors concluded that the licensee's performance was good and
that the approach toward the events was from a safety aspect.
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licensee demonstrated good teamwork practices during the events and in-
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the. case of the October 23 SG tube leak, developed complex effective teams involving several departments within the station, members from
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another facility (Byron), and industrial representatives (Westinghouse).
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All of the events involved challenges to the operating staff and the plant.
In all cases, the operations staff mitigated the transients.
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i In the case of the inadvertent deenergization of Bus 243, the root cause of inadequate written instructions was in violation of 10 CFR 50,
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Appendix B.
Since the licensee identified and corrected the cause and-l met the requirements of 10 CFR 2, Appendix C, Section VII.B.(2), this is
considered to be a non-cited violation.
i The inspector considers that an opportunity to demonstrate an additional measure.of an approach towards safety was missed during the response to
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the October 23 SG tube leak. Although conservatism more than required by technical specifications and an evident safety approach was
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demonstrated by initiating a shutdown to cold-depressurized conditions,
a reduction in power was not initiated during a period that the leak was
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known to exist and before the administrative limit was reached.
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Another missed opportunity was the lack of an existing administrative I
limit prior to October 23.
l It is recognized that the licensee's corrective actions of establishing an administrative limit of 150 gpd and requiring shutdown with increases
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of rate resolves these concerns.
l 5.
Monthly Maintenance Observation (62703)
k Routinely, station maintenance activities were observed and/or reviewed by the inspectors'to ascertain that they were conducted in accordance j
with approved procedures, regulatory guides and industry codes or
standards, and in conformance with technical specifications.
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The following maintenance activities were observed and reviewed:
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Unit 2 Condenser / Water Box Repairs
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Unit 1 Steam Generator Eddy Current Testing Preparations
Unit 2 feedwater Regulating Valve (2D) Repairs
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Feedwater Regulating Valve Positioner Inspection
After the Unit 2 trip on October 3, the condenser was entered for an inspection to investigate mechanical noises discovered on September 29.
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The licensee discovered various structural damages to internal i
components. The majority of the indications were due to erosion / corrosion associated with exposure to steam from an expansion
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joint failure on an extraction steam line exhausting internal to the l
condenser. The licensee's corrective actions included replacing the
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expansion joint with a double ring seal joint. The newer double ring design is less sutceptible to failure.
During the maintenance activities, good itdustrial safety was demonstrated.
During the performance of activities associated with the preparations and restoration after eddy testing on the IC steam generator, maintenance personnel demonstrated good industrial safety and radiological protection practices.
I No violations or deviations were identified.
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6.
Monthly Surveillance Observation (61726)
The inspectors observed several of the surveillance testing required by l
technical specifications during the inspection period and verified that-
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testing was performed in accordance with adequate procedures, that test
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instrumentation was calibrated, that results conformed with technical j
specifications and procedure requirements and were reviewed, and that i
any deficiencies identified during the testing were properly resolved.
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The.following surveillance activities were observed and reviewed:
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Portions of Units I and 2 Reactor Protection system
- Unit 2 Diesel Generator
Unit 1 Overpower Trip (RPS) High Range Setpoint Adjustment.
No violations or deviatiens were identified.
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7.
Plant Scaffoldina
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I During a review of site requi.rements for erecting scaffolding, the inspector determined that the site was not adequately addressing seismic requirements for scaffolding in safety-related applications, i.e.
adjacent or over operating or operable safety-related equipment.
It should be noted that the licensee's corporate office had undertaken a project to provide improved engineering analysis of scaffolding designs, a evidenced through draft technical information directives. The
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licensee generated Plf 456-201-93-40200 to address their identified concerns for scaffolding in the diesel generator oil tank rooms.
The existing PIF will be revised to incorporate additional general concerns i
on their overall scaffolding process. The additional areas to be
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covered include:
1) lack of training of personnel in seismic requirements (botS CECO and contractor crafts responsible for erecting scaffolding); and 2) following scaffold erection, a review and. sign off for a structural (seismic) inspection for seismic requirements on the Scaffold Inspection Tag required by scaffolding procedure BwAP 400-21.
- Consideration is being given to have both the training and inspection
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conducted by structural engineers from the SEC Department.
[10 violations or deviations were identified.
8.
Enoineerina and Technical Supoort t
The October 23, 1993 Unit I shutdown due to a primary-to-secondary leak
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on the-1C stean generator provided a challenge to the engineering and
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technical support organizations.
Braidwood formed a technical review -
team, compriseo of Braidwood, Byron, corporate, and Westinghouse (vendor) enginee. ing to determine the appropriate actions to identify
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and correct the leak.
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i The leak was identified in tube 49/76 (Row 49, Column 76), a peripheral tube.
Bobbin coil eddy current testing identified a 5/8 inch long through wall crack in the free span region of the tube bundle.
Subsequent rotating pancake coil (RPC) eddy current testing identified a
1.3 inch longitudinal crack with a 5/8 inch breach that was superimposed
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on a scratch about 18 inches long, j
The scratch was believed to either be due to a manufacturing flaw or
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from maintenance activities in 1987.
Subsequent RPC testing eliminated i
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the possibility of the scratch being caused by previous maintenance l
activities since similar scratches were not discovered on other
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I peripheral tubes.
RPC testing sample size included all tubes within the l
outer two rows and adjoining columns to tube 49/76.
This testing did not reveal any similar scratches.
The licensee concluded that the
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affected tube was an isolated occurrence.
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In addition, the affected steam generator was 100% end-to-end bobbin i
coil eddy current tested.
116 tubes were identified with greater than i
40% through-wall degradation.
These tubes were evaluated for abnormal-
growth rates compared to the 1992 refueling outage data.
No. abnormal
growth rates were identified.
The 116 tubes had indications of cracking
in the support plate areas versus the freespan of tube 49/76 and
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required plugging.
These actions were considered to be appropriate and resulted in the
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ability to return the unit to service on November 12.
i No violations or deviations were identified.
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i 9.
Plant Support i
During this inspection period, two events occurred that provided l
challenges to organization providing plant support.
The October 3,-
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Unit 2 trip, and October 23 Unit I shutdown required coordination and
teamwork by several site departments.
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The October 3 event requirm
, ordination involving the radiation-protection and chemistry s.,artments.
Unit 2 has a known existing i
leaking fuel element.
After the trip, Im spiked to elevated levels
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which affected dose rates in specific locations within the auxiliary
building.
The radiation protection department promptly surveyed the
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areas and ensured that posting was accurate. These efforts were based
upon an existing plan developed prior to the event.
These efforts
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minimized the dose accumulated during the outage.
l The chemistry department also responded to the I spike by imolementing m
their existing action plan.
Because of the increased samplirg
frequency, the duration of the spike was well trended. This assisted in the planning of maintenance activities without increasing the risk of j
accumulating additional dose.
i The October 23 tube leak required coordination involving radiation protection, chemistry, operations, engineering, and licensing
departments.
The most notable evidence of good planning and teamwork
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was that accumulated total dose of 14.2 person-rem was below the planned -
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15.9 man rems.
This was achieved even though the outage was extended
from 13 to 21 days to accommodate the 100% eddy current testing of the l
10 steam generator.
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The October 23 event also required a N0ED and an emergency technical j
specification amendment by the licensing department. On November 5, the i
Office of Nuclear Reactor Regulations (NRR) prompted the licensee.to
request an enforcement discretion (N0ED) and an emergency technical
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specification amendment. The N0ED was determined to be necessary
because the licensee appeared to be in violation of Technical i
Specification (TS) Action Requirement 4.4.5.2.
The licensee had not i
recognized the subtle requirements of the TS Action Requirement because i
Limiting Condition of Operation (LC0), TS 3.4.6.2.c was not exceeded.
Normally, a TS Action Requirement is entered because the LC0 is-exceeded.
However, TS Action Requirement 4.4.5.2 is also related to i
inservice testing and can be entered without exceeding the LCO, due to i
inservice testing requirements.
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The licensing department was subsequently requested to provide
additional information to complete the N0ED process.
An evaluation of the licensing department's performance was not done by the inspectors.
No violations or deviations were identified.
t 10.
Temporary Instruction (TI) 2500/028 - Employee Concerns procram i
The inspectors reviewed the licensee's employee concerns program as
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requested by the subject 11.
The inspectors did not identify any concern;.
No violations or deviations were identified.
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11.
Report Review During the inspection period, the inspector reviewed the licensee's
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Monthly Performance Reports for August, September, and October 1993.
The inspector confirmed that the information provided met the j
requirements of Technical Specification 6.9.1.8 and Regulatory Guide
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1.16.
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The inspector also reviewed the licensee's Monthly Plant Status Reports for August, September, and October.1993.
No violations or deviations were identified.
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12.
Violations for Which A " Notice of Violation" Will Not Be issued f
The NRC uses the Notice of Violation as a standard method for i
formalizing the existence of a violation of a legally binding i
requirement. However, because the NRC wants to encourage and support j
licensee's initiatives for self-identification and correction of j
problems, the NRC will not generally issue a Notice of Violation for a
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violation that meets the tests of 10 CFR 2, Appendix C, Section
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VII.B.(2).
These tests are:
1) the violation was identified by the-
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licensee; 2) the violation would be categorized as-Severity Level IV
or V; 3) the violation will be corrected, including measures to prevent; j
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recurrence, within a reasonable time period; and 4) it was not a violation that could reasonably be expected to have been prevented by the licensee's corrective action for a previous violation.
A violation of regulatory requirements identified during this inspection for which a Notice of Violation will not be issued is discussed in Paragraph 4.
13.
Exit Interview (30703)
The inspectors met with the licensee representatives denoted in Paragraph I during the inspection period and at the conclusion of the inspection on November 19, 1993.
The inspectors summarized the scope and results of the inspection and discussed the likely content of this inspection report. The licensee acknowledged the information and did not indicate that any of the information disclosed during the inspection could be considered proprietary in nature.
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