ML20034G887
| ML20034G887 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 02/26/1993 |
| From: | Gagliardo J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20034G880 | List: |
| References | |
| 50-458-92-35, NUDOCS 9303120054 | |
| Download: ML20034G887 (26) | |
See also: IR 05000458/1992035
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APPENDIX B
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
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Inspection Report:
50-458/92-35
Operating License:
Licensee:
Gulf States Utilities
P.O. Box 220
St. Francisville, Louisiana 70775-0220
Facility Name: River Bend Station
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Inspection At:
St. Francisville, Louisiana
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Inspection Conducted: December 20, 1992, through January 30, 1993
Inspectors:
W. F. Smith, Senior Resident Inspector
D. P. Loveless, Resident Inspector
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E.jE.
ollins, Project Engineer
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Approved:
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E.'(gbliardo, Chief,ProjectSectionC
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Inspection Summary
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Areas Inspected:
Routine, unannounced inspection of plant status, onsite
response to events, operational safety verification, maintenance and
surveillance observations, review of licensee procedures based on an industry
event, followup on corrective actions for violations, and onsite review of
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licensee event reports.
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Results:
The licensee's actions to resolve the inadvertent isolation of the
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reactor core isolation cooling system were appropriate (Sects.on 2.I).
The licensee's identification, analysis, and dispositioning of the
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neutron activation of corrosion inhibitors in the modified service water
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system were handled in an excellent and conservative manner
(Section 2.2).
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The licensee's response to and corrective actions for the failure of a
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containment personnel airlock door were considered good (Section 2.3).
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Overall, the licensee's response to operational events during this
inspection period was very good.
None of the events involved operator
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error (Section 2.4).
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Operations observed in the control room indicated good professionalism
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and formality (Section 3.1).
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Plant personnel failed to identify several conditions adverse to quality
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including:
rain water wetting electrical equipment in the auxiliary
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building, copious quantities of metal chips on safety-related equipment,
and oil leaks from electrohydraulic valve operators. This was
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considered a weakness. The licensee's corrective response was excellent
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(Sections 3.2.1, 3.2.2, and 4.2).
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The completion of equipment preservation and coating activities in
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Tunnel G was viewed as a strength (Section 3.2.5).
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One violation was identified for repeated inappropriate accesses to the
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protected area by personnel whose general employee training had expired.
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The failure to prevent these recurrences indicated a lack of management
attention to ensure timely and effective corrective action
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(Section 3.3).
One noncited violation was identified for failure to post a Notice of
Violation and Proposed Imposition of Civil Penalty in accordance with
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10 CFR Part 19.11. The documents were immediately posted, and
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comprehensive corrective action was taken (Section 3.4.1).
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Four unidentified personnel were observed violating a radiologically
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controlled area barrier to make an unauthorized exit. The licensee
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implemented prompt actions to identify the individuals, prevent a
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recurrence, and document those actions. An unresolved item was opened
(Section 3.4.2).
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The licensee's Performance Improvement Program, implemented during .
January 1993 to correct the root causes of poor performance in
radiological controls was excellent and the licensee appeared to have
expended considerable management and supervisory resources to support
this effort (Section 3.4.3).
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A weakness was identified in that the licensee did not distribute, in a
timely manner, the 1992 annual directive pertaining to the shift
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supervisor's control room command functions pursuant to Technical
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Specification 6.1.2 (Section 3.5).
A weakness was identified regarding the licensee's placement of oil
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absorbent material in Sump IDFR-TK5A without evaluating the impact on
the operability of the suppression pool pumpback system (Section 3.6).
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Overall, the licensee operated the facility in a safe manner during this
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inspection period and was responsive to identified weaknesses
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(Section 3.7).
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A quality control inspector rejected a replacement electrical component
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which did not have sufficient documentation to support its qualification
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as Category I.
This was an example of quality assurance strengths at
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River Bend Station (Section 4.1).
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Repair work observed on two safety-related valve actuators was
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considered very good (Section 4.3).
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The licensee's evaluation and corrective actions for maintenance
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problems with Borg-Warner electrohydraulic actuators was adequate to
maintain operability of affected plant safety-related systems
(Section 4.4).
Overall, the maintenance activities observed during this inspection
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period were good (Section 4.5).
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Operators did not appear to understand the proper use of test gauges
during the performance of a new pump and valve inservice test procedure.
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Also, the procedure had many editorial errors, indicating that a poor
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validation had been performed. The licensee was already taking actions
to improve performance in this area (Section 5).
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The procedural guidance provided for the operators was good and appeared
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to be effective at addressing reactor vessel temperature stratification
(Section 6).
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Summary of Inspection Findings:
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Violation 458/92035-1 was opened (Section 3.3).
A noncited violation was identified (Section 3.4.1).
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Unresolved Item 458/92035-2 was opened (Section 3.4.2).
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Violations 458/90029-4, 458/91015-1, and 458/92008-2 were closed
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(Section 7).
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Licensee Event Reports91-011, 92-011,92-015, 92-023,92-027, 92-028,
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and 92-029 were closed (Section 8).
Attachments:
Attachment 1 - Persons Contacted and Exit Meeting
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DETAILS
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1 PLANT STATUS
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On January 8, 1993, the licensee reduced power to 73 percent to facilitate the
repacking of Feedwater Regulating Valve C.
With this exception, the plant was
operated at essentially 100 percent power throughout this inspection period.
Routine minor power reductions were performed to facilitate cleaning of water
boxes and turbine valve testing.
2 ONSITE RESPONSE TO EVENTS (93702)
2.1
Inadvertent Isolation of Reactor Core Isolation Cooling (RCIC)
On December 30, 1992, the plant was operating at full power. While instrument
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and control technicians were performing the residual heat removal equipment
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area ambient temperature high channel functional t st, RCIC Steam Supply
Valve IE51*MOVF064 cycled closed. This valve was also a containment isolation
valve and, by closing, it isolated the steam supply to the RCIC pump turbine,
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thereby rendering the system inoperable.
This engineered safety features
actuation occurred at 12:11 p.m., and the shift supervisor reported the event
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to NRC headquarters at 2:18 p.m., as required by 10 CFR Part 50.72. The shift
supervisor declared the system inoperable and entered the action statement for
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Technical Specification 3.7.3, which allowed continued plant operation for up
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to 14 days provided high pressure core spray was operable.
The technicians verified that no errors were made during the test and noted
that the trip unit was successfully exercised twice without an actual
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isolation before the actuation occurred.
In addition, the technicians
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repeated the entire test and no actuation occurred. The test procedure
required certain leads to be lifted and jumpers to be installed to prevent
actual isolations.
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The inspectors reviewed the licensee's efforts to determine the cause.
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was no indication of the cause, except that an unwanted isolation had
occurred.
Troubleshooting was conducted on the basis of elimination of eight
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possible causes, each of which was eliminated. The test was again performed
successfully. Two switches and a relay, each considered most likely to have
failed momentarily, were replaced. The new components were satisfactorily
retested and the RCIC system was restored to a standby status.
The inspector
considered the licensee's actions to resolve the cause of the engineered
safety features actuation to be appropriate.
In view of the failure having
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been associated with the surveillance test, and the safety function having
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been successfully actuated, no additional action was necessary.
2.2 Activation of Service Water System Treatment Chemicals
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On September 28, 1992, the licensee's chemist reported the presence of
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Sodium-24, an activation product, during his weekly gamma isotope analysis of
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samples obtained from the normal service water (SWP) system. The
concentration was reported at 2.6E-7 microcuries per cubic centimeter (uC/cc).
A condition report (92-0816) was initiated and the licensee evaluated the
condition and determined the cause to be neutron activation of corrosion
inhibitors, all of which contained sodium.
The activation appeared to take
place in the drywell unit coolers. They have been exposed to neutron
radiation leakage while the reactor was at power.
Frilowing completion of modifications to convert service water to a closed
'oop system during Refueling Outage 4, which was completed in early
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September 1992, a chemical treatment program was implemented for the SWP
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system to reduce corrosion. The chemicals used were sodium molybdate, sodium
nitrite, sodium hydroxide, and Tolyltriazole. All of these chemicals
contained sodium, and typical concentrations of sodium in the system were 200
to 400 parts per million.
"y December 23, the licensee determined that, after several weeks of full
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power operation, Sodium-24 concentrations appeared to be leveling off to
approximately 2.8E-7 uC/cc. With a 10 CFR Part 30.70 exempt concentration of
2E-3 uC/cc, this did not constitute a radiological hazard. Sodium-24 has a
half-life of 15.03 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. However, the molybdenum component of the ' sodium
molybdate additive, when activated, decays with a 3-day half-life to
Technetium-99, which has a half-life of 2.14E5 years.
Thus, over the life of
the plant, this radionuclide could continuously concentrate with power
operation time.
Based on calculation from the concentrations of-
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Molybdenum-99, the licensee determined that, even if the plant was operated at
full power continuously for 40 years, no service water was lost, and the
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Technetium-99 did not decay at all, there would still be less than a
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detectable concentration.
Specifically, the licensee calculated that there
could be as much as 2.71E-3 uC of Technetium-99 in the entire 59,063 cubic
feet volume of the SWP system. 2.71E-3 uC, which equated to about
100 disintegrations per second spread over the entire system surface area,
would not create detectable levels of long term contamination of the system
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components or piping.
The licensee concluded, based on the calculations, that the generation of
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Technetiam-99 was negligible. The licensee also concluded that, although the
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SWP system was considered to be potentially contaminated, as described in the
Updated Safety Analysis Report (USAR), the potential for residual heat removal
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system heat exchanger tube leakage dictated that operation in the contaminated
condition on a permanent basis would require a change to the plant as
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described in the USAR.
Therefore, the licensee performed a safety evaluation
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pursuant to 10 CFR Part 50.59 and determined that an unreviewed safety.
question would not be created by the change.
For the lang-term, the licensee informed the inspectors that they did not
intend to operate the SWP system in this manner indefinitely.
Design reviews
were in progress to upgrade the turbine building chilled water pumps to
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provide sufficient cooling capacity so that the drywell unit coolers may be
added during plant operations. The drywell unit coolers were already piped
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and valved into the turbine building chilled water system anu had been
utilized during outages to air condition the drywell for personnel
habitability.
The licensee's analysis of the neutron activation of corrosion inhibitors and
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microbiocide in the SWP system was thorough. The licensee considered
Inspection and Enforcement Bulletin 80-10, " Contamination of Nonradioactive
Systems and Resulting Potential for Unmonitored, Uncontrolled Release of
Radioactivity to Environment," and performed a comprehensive safety evaluation
pursuant to 10 CFR Part 50.59 for interim operations until the turbine
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building chilled water system could be upgraded to assume the drywell-cooling
load. The licensee's actions on this issue were excellent.
2.3 Failure of Containment Airlock Seal Flnnae Bolting
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On January 4,1993, the 171 foot elevation containment airlock outer door was
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jammed by a loose bolt on the seal flange.
The door would neither open or
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close and was s'uck approximately 2 inches open.
The licensee declared the
door inoperable and locked closed the inner door in accordance with Technical Specification 3.6.1.4, Action a.1.
Prompt Maintenance Work Order R059390 was
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issued to repair the door.
The mechanics dispatched to the airlock freed the door; however, the door sill
was marred.
The mechanics buffed the scratch on the sealing surface for the
inner seal of the outer door. Working one bolt at a time, the mechanics
removed each bolt from the bottom seal flanges and cleaned and tapped the
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hole. The bolt was then reinstalled with Locktite 271 fu better ensure that
it would remain in place.
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Following this work, Surveillance Test Procedure STP-057-3705, " Primary
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Containment Air Locks Seal Leakage Rate Test," was performed with satisfactory
results. On January 6, the shif t supervisor declared the airlock operable and
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exited the action statement of Technical Specification 3.6.1.4.
2.4 Conclusions
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No operation events during this inspection period involved operator error.
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The licensee's actions to resolve the inadvertent isolation of the RCIC system
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were appropriate. After modifying the normal service water system to a closed
system, some of the corrosion inhibitors containing sodium became neutron
activated.
The licensee's identification, analysis, and disposition of the
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issue were handled in an excellent and conservative manner
The licensee's
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response to the failure of a containment personnel airlock door was considered
good.
Overall, the licensee's responses to operational events was very good.
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3 OPERATIONAL SAFETY VERIFICATION (71707)
The objectives of this inspection were to ensure that this facility was being
operated safely and in conformance with regulatory requirements and to ensure
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that the licensee's management controls were effectively discharging the
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licensee's responsibilities for continued safe operation.
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3.1 Control Room Observations
On a daily basis, when on site, and periodically during back shift
inspections, the inspectors observed control room operations and shift
turnover. The operators exhibited good communications with personnel inside
and outside the control room. Turnovers appeared to be complete and accurate.
Shift meetings attended by the inspectors were held in a formal and
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professional manner, and the shift supervisors' expectations were well
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communicated. During this inspection period, the inspectors noted good
professionalism and formality in the control room.
3.2 Plant Tours
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During the plant tours conducted by the inspectors, the issues discussed below
were identified. Overall, the inspectors were concerned that plant staff who
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normally tour the areas, including the nonlicensed equipment operators, were
not identifying these problems in a timely manner, if at all. The licensee
was already addressing the concern under their response to
Violation 458/92034-3, ard was performing training and taking procedural
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actions to ensure that t i equipment operators would be sensitive to such
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problems and identify the
for correction. The inspectors will continue to
monitor progress in this
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3.2.1
Rain Leakage into 1 e Auxiliar_y Buildinq
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On January 7, 1993, the in: 'ctors were conducting a tour of the auxiliary
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building and noted an unusu 'v large amount of water flowing down the shield
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building walls on the ll4-fe. elevation and the 141-foot elevation.
Some of
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the water was flowing behind some electrical penetration ca'oinets and wetting
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the cables.
The inspectors vere unable to see if the terminal strips inside
the cabinets weie being wetted.
This was brought to the-attention of-the-
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licensee, who investigated and found a hole in the rubber seal at the roof
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where the shield building joined the auxiliary building roof. This was
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temporarily repaired and the leakage subsided.
The licensee's system
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engineers evaluated the inside of the cabinets and found no problems. The
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absence of unwanted grounds in the electrical systems tended to support the
evaluation.
The inspectors expressed concern to the plant manager that the
leakage was not first identified by plant personnel at or near the time the
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leakage started.
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3.2.2
Failure of Plant Personnel to Identify Housekeeping Deficiencies
On January 7, while in the auxiliary building on the ll4-foot elevation, the
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inspectors noted copious quantities of metal chips on the floor and on the
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reactor plant component cooling valves and piping above.
The source was
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hydrogen mixing system solenoid Air Valve CPP*S0V140, which was repaired in
early December 1992.
The valve was above the grating just below the 141-foot
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elevation floor. This poor housekeeping practice was brought to the attention
of the licensee's maintenance supervisor, who took action to clean _it up. The
inspectors expressed concern to the plant manager that plant personnel allowed
the metal chips to remain on equipment and piled on the floor for over 4 weeks
before it was identified by the inspector.
3.2.3
Review of Maintenance issues
The inspectors also found that vent holes in the bottom of the enclosure for
the electrohydraulic operator for main steam positive leakage control system
Pressure Control Valve IE33*PVF022 had been taped over with duct tape. The
reason was not apparent, but one of the holes had hydraulic fluid leaking past
the tape.
This condition was brought to the attention of licensee management.
The inspector noted that this practice of taping over the vent holes on Borg-
Warner valve operator enclosures could be masking potential hydraulic
failures. The inspectors noted that this practice was also apparent on
Valve IE33*PVF002.
Section 4.2 of this report addresses this issue in more
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detail.
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During other tours, the inspectors noted that Temperature Recorder C11-TR-R018
on local Panel P007 in the auxiliary building had been inoperable since
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January 1992 and had several deficiency tags attached.
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indicated control rod drive mechanism (CRDM) temperatures and the
effectiveness of control rod drive system cooling water to each CRDM.
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temperature monitor was designed to annunciate in the main control room when
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any control rod drive temperature exceeded 250 F.
This feature was addressed
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in the USAR, Chapter 4.6, as providing one indication of certain failures in
control rod hydraulics.
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System Operating Procedure 50P-0002, Revision 7, " Control Rod Hydraulics
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(System #052)," Section 2.5, instructed the operators to not permit CRDM
temperatures to exceed 250 F, as seal life would be drastically decreased.
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The procedure also stated that CRDM temperatures above 350oF reduced seal
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strength and may result in measurable delay in scram response times.
Section 6.4.had a caution that directed the operator to monitor CRDM
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temperatures once per hour when isolating CRDMs for maintenance during reactor
operations.
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The inspectors expressed concern that the apparent abandonment of the CRDM
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temperature monitor constituted a change to the control rod drive system as
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described in the USAR and, as such, should have been either repaired in a
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timely manner or evaluated pursuant to 10 CFR Part 50.59. The licensee's
response to the concern was that the temperature recorder was not abandoned,
but by selection of priorities its maintenance was delayed for the purpose of
allocating maintenance resources to other work of greater importance.
The
licensee based this decision partly on the extensive increased scope of
maintenance performed on CRDMs during the last refueling outage because of a
detailed analysis on CRDM seal performance, stall flows, and rod pull records.
The licensee stated that they planned to repair the recorder as soon as the
parts become available. The inspectors were satisfied that the licensee was
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taking reasonable actions to restore the recorder to service and that their
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rationale for deferring work on the recorder to accomplish higher priority
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work was acceptable.
3.2.4
Industrial Safet_y Issues
During tours of the plant throughout the first week of January, the inspector
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noted that safety chains for ladders had been left unhooked repeatedly.in the
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high pressure core spray pump room. The inspector discussed this with the
-Senior Production Safety Specialist and the fire watch supervisor. The safety
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representative informed the inspector that the policy at River Bend Station
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has required employees to leave safety chains open when no one was in the area
and there was only one entrance to the elevated area.
The high pressure core
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spray pump room was not such an area.
The fire watch supervisor. suggested
that there may have been some confusion on the part of the fire watches and
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that he would discuss the requirements for safety chains with the fire
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watches.
The inspectors did not find any safety chains unhooked during the
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remainder of the inspection period; however, during the exit meeting of
February 1, the inspectors expressed a minor concern that the safety chain
policy appeared vague and, as such, may cause confusion in the future.
The
licensee acknowledged the concern.
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3.2.5
Preservation of Plant Eouipment and Systems
During various plant tours, the inspectors noted progress in the cleaning and
painting of various systems and structures in the plant.
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noteworthy was the standby. SWP system piping and structures in Tunnel G.
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Inspection Reports 50-458/89-14 and 50-458/92-18 document heavy oxidation of
unpainted welds and base plates in the standby SWP system. At that time. the
licensee revised Quality Check List QCL-MSP-0014-04 to add a check of piping
components and their attachments for excessive rust. As a preventive measure,
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the licensee issued Maintenance Work Order R126452 to apply protective
coatings to affected surfaces in Tunnel G.
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This work had been completed.
The quality of the job was such that it should
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provide a positive demonstration of high performance expectations, help
improve worker pride and ownership, and provide for the long-term preservation
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of safety-related systems in the area.
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3.3 Security Observations
On October 15, 1992, a visiting NRC inspector was issued his unescorted access
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key card and entered the protected area, even though his general employee
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training had expired several months earlier.
By procedure, this training must
be current before an individual could be granted unescorted access.
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licensee identified the violation several hours later and took excellent
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corrective action. The details of this incident were discussed in NRC
Inspection Report 50-458/92-32. The inspectors used enforcement discretion,
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as permitted by 10 CFR 2, Appendix C, and NRC's Enforcement Policy and did not.
cite the incident as a violation.
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The licensee had committed to implement a feature of the access computer
program which will automatically deny access to all personnel whose training
had expired. This feature will be a backup to physically pulling key cards
from the rack when the training department has informed security that an
individual's training had expired.
This action was scheduled to be completed
by December 1, 1992.
By December 1, the new feature was implemented, and the resident inspectors
were so advised.
However, the inspectors were not informed that, for a
variety of reasons, there were 71 names whose expiration date was entered as
"00/00/00." That meant to the computer that the expiration dates were
indefinite, and the computer would not prevent access for those individuals on.
the list whose training had expired. The training for 1 of the 71 individuals
on the list had expired on November 30, 1992, and, as a result of the untimely
resolution of the 71 names, was inappropriately granted access on December 3,
7, 10, 17, and 21.
In addition, five other individuals had failed general
employee training exams but, due to a training department error, neither the
individuals nor security had been informed. This occurred earlier in 1992
after the passing grade was increased from 70 percent to 80 pert.
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Consequently, 3 of the 5 individuals inappropriately obtained unescorted
access to the protected area at various times. One individual obtained access
on December 4, 16, and 17, after the corrective action could have been
completed. This was contrary to Section 6.6.2.3 of Training Program'
Procedure TPP-7-018, Revision 5, " General Employee Training."
The above problems were identified by the licensee on January 4,1993, when
another visiting NRC inspector's key card was still in the key card rack at
the primary access point, even though his training had expired.
In this case,
the key card was not requested for entry into the protected area because the
visiting inspector knew his training had expired. Condition Report 93-0001
was initiated by the licensee, and the expired key card was pulled.
The licensee completed their corrective actions by January 12 and provided the
inspectors with a security computer printout to demonstrate that all 71 items'
had been resolved. The inspectors reviewed the printout and found no
discrepancies.
Failure to comply with Procedure TPP-7-018 is a violation
(458/92035-1) of Section 3.4 of the licensee's Physical Security Plan, which
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requires that personnel authorized unescorted access to the protected area be
given annual training for refamiliarization on security procedures.
3.4 Radiation Protection Activities
3.4.1
Posting of Regulatory Information
On January 29, 1993, the inspector reviewed the regulatory information
bulletin boards on site.
The inspector noted that the most recent Notice of
Violation and P- ) posed Imposition of Civil Penalty, dated December 28, 1992,
was not posted.
10 CFR Part 19.11(a)(4) states that each licensee shall post
current copies of any Notice of Violation involving radiological working
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conditions or Proposed Imposition of Civil Penalty within 2 working days after
receipt of the documents from the Commission.
The licensee stated that this document was not posted, in error, and
immediately posted the document, along with the licensee's response.
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licensee stated that, in the future, licensing engineers would be required to
determine if posting is required under Part 19.11 upon receipt of a document.
Nuclear Licensing Procedure NLP-10-006, " Processing and Trading of Regulatory
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and Industry Correspondence," would be revised to require this review.
Additionally, the licensee's Internal Distribution System " Blue Sheet" would
be revised to add a question for all NRC violations and responses to ask the
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engineer if posting was required. The safety significance of this violation
was minor and it was corrected immediately.
In addition, the licensee
committed at the exit meeting to take the above corrective actions to prevent
recurrence. Therefore, this meets the criteria specified in paragraph VII.B.1
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of Appendix C to 10 CFR Part 2 for a noncited violation and, accordingly, this
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issue will not be cited in the Notice of Violation, Appendix A, to this
report.
3.4.2
Failure to Observe Radiological Barriers
On January 29, 1993, the licensee informed the resident inspectors that, on
January 27, four individuals were observed by a security officer to have
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exited the radiologically' controlled area in an unauthorized manner. They
crossed the posted barrier in Tunnel C and entered the normal switchgear
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building before the officer could stop them and identify them by name.
However, the officer noted that at least three of the four individuals were
wearing a blue hardhat, which was unique to a contractor that performed
radioactive decontamination services for the licensee. The officer notified
health physics personnel, and the appropriate licensee managers were informed.
An investigation was promptly implemented utilizing plant security, corporate
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security, radiation protection, and contractor personnel.
By February 1, the
licensee temporarily denied access to the plant for four contractor personnel,
based on strong evidence that they were the individuals seen crossing the
radiological barrier-in violation of plant procedures. The licensee stated
that the four individuals denied having been in the area of the barrier at the
time of the violation, but there appeared to be evidence to the contrary. The
licensee was continuing the investigation to determine whether the correct
individuals were identified and whether they intentionally violated the
barrier and documented their findings.
The licensee was also implementing
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other corrective actions as this inspection period ended.
For example,
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surveys were conducted to ensure that there was no spread of contamination'in
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uncontrolled areas entered by the individuals. No contamination was found.
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The seriousness with which this incident was viewed by the licensee was
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communicated to the contractor's senior and line management.
This
communication included the licensee's willingness to terminate their contract
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if the guilty parties were not promptly identified. The contractor's foremen
were directed to observe all of their personnel exiting the radiologically
controlled area.
Additional training, and meetings of all contractor
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personnel with the Plant Manager, were conducted.
The contractor's senior
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management also decided to perform spot-checks of foremen performing their
supervisory functions.
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The licensee stated that they were documenting all investigation findings and'
corrective v tions for NRC review.
This problem appeared, based on partial
information supp ied to the inspectors, to be a violation of the licensee's
Radiation Protectia Procedure RPP-0043, Revision 4. Section 1.3, which
required _ personnel .:xiting the radiologically controlled area to conduct
personal monitorin for contamination. Although it was apparent that the
licensee was taking prompt and comprehensive corrective action on this matter,
more information is iequired to ascertain the circumstances involving this
failure and its relationship to similar failures _ that have occurred at River
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Bend Station previously. Therefore, this item is unresolved pending further
review (458/92035-2).
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3.4.3
Radiolooical Protection Performance Improvemant Program
On January 8 and 15, the inspector attended two of the Radiation Protection
Performance Improvement Program sessions conducted with all levels of licensee
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nanagement and supervision. This program was initiated as part of the
response to the Notice of Violation and Proposed Imposition of Civil Penalty
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. issued by NRC because of significant violations of NRC requirements in
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eadiation protection. Details were documented in NRC Inspection
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Raort 50-458/92-33 (EA 92-207).
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The improvement program was initiated by a 1-hour presentation given by key
plant management staff members to licensee personnel each day of the first
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week in January. The inspector noted a high degree of enthusiasm and a
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determ nation to get full participation on improving performance in the
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radiation protection area across all affected disciplines. During the second
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week in January, six teams with a good cross section of supervisory
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representation, were convened each day to develop ideas for improvements and
provide a documented report of the results of their efforts. During the third
week, six craftsmen "high performance teams" were assembled to participate in
the program and bring their perspective into solving the overall problem of
radiation protection performance.
The sessions observed by the inspector
appeared meaningful, constructive, and positive from a team building
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perspective. The licensee demonstrated a strong resolve to improve
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performance to a high level.
It was evident that a considerable amount of
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resources and time were expended on this effort.
The inspectors were given an extensive listing of recommendations from the
various groups. The inspectors will followup on the degree and extent of
actual implementation.
3.5 Administrative Technical Specifications Review
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On December 31, 1992, the inspector reviewed selected administrative Technical
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Specification requirements to determine 14censee compliance.
This review was
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prompted by recent changes in the management of the operations and maintenance
departments. The inspector verified that the new plant manager was aware of
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his responsibilities for the overall unit operation and that the succession to
this responsibility during his absence was clearly delegated in writing.
The inspector determined that the acting Operations Supervisor and the acting
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Assistant Operations Supervisor were aware of their responsibilities-and that
each held an active senior reactor operator license in accordance with
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Technical Specification 6.2.2.g.
The inspector reviewed the shift supervisor's responsibilities for the control
room command function.
Previous NRC inspections have indicated that the shift
supervisor was recognized as having the responsibility for all activities
relating to station operation and safety. However, Technical Specification 6.1.2 requires that a management directive to this effect,
signed by the Senior Vice President - River Bend Nuclear Group, shall be
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reissued to all station personnel on an annual basis.
The inspector
Catermined that this directive had not yet been reissued in 1992.
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Ai er the inspector brought this item to the attention of the licensee, the
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licensee reissued the directive on December 31.
This action met the
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requirement of Technical Specification 6.1.2; however, the licensee's failure
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to issue the directive in a timely manner was considered a weakness. The
licensee stated that during 1992 this directive was reviewed and reissued
without change, but the responsible organization failed to realize that
Technical Specifications required that it be distributed to all plant
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personnel.
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A change was made to the directive stating that it will be reissued and
distributed every year in accordance with Technical Specifications. The
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inspector concluded that this corrective action was appropriate to address the
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weakness.
The inspectors questioned whether other administrative Technical
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Specifications were being properly implemented. The licensee stated that the
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problem with the above directive was an isolated case and that a review of
other administrative requirements for compliance was not warranted.
3.6 Operability of Suppression Pool Pumpback System
On January 4,1993, the inspector identified two onion sacks containing oil
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absorbent material floating in the auxiliary building Crescent Area
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Sump DFR-TKSB.
The sacks were tethered with nylon ropes and were floating in
the sump in the vicinity of the safety-related Suppression Pool Pumpback
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System Pump suctions. The inspector informed the shift supervisor of the
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condition and questioned the operability of the system and the possible
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blockage of the sump pumps.
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The licensee initiated Condition Report 93-0002 to document the condition and
evaluate system operability. The oil absorbent material was installed as part
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of the radioactive waste minimization program to collect oil from the sumps.
The shift supervisor directed the material to be removed from the sump until
an evaluation of the impact could be performed.
In addition, all emergency
core cooling system sumps were inspected to ensure that similar material had
not been installed.
During their evaluation, the liceneee determined that Procedure RWS-0208,
" Water Management and Leak Detect.on," Section 5.5 required that oil
absorbent pillows be placed in . umps for oil collection and removal to reduce
the risk of sending oil to the radioactive waste treatment system. A
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determination was made that sumps containing oil absorbent pillows were
checked on a daily basis and that there was never an instance where a pillow
was saturated to a point that it sank.
The design of the system caused both pumps to shutoff when the water level
fell to 16 inches.
The pump suctions were at approximately 5 3/4 inches.
Because the pillows were known by licensee personnel to always be afloat,
there was never ;n instance when a pillow was obstructing any pump suction.
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Therefore, the licensee concluded that the suppression pool pumpback system
had remained operable throughout the time frame that the absorbent material
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was present in the sumps.
The licensee was considering a revision to Procedure RWS-0208 to include a
caution that oil absorbent pillows were not to be placed in Sumps IDfR-TK5A
and IDER-TK58 while the system is operable.
In addition, the revision would
provide a positive means to control the inspection and timely removal of any
oil absorbent pillows that may be placed in emergency core cooling system pump
room sumps, even though these sumps were not safety related, because the sumps
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provided a function that was important to safety.
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3.7 Conclusions
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Overall, the licensee operated the facility in a safe manner during this
inspection period and was responsive to identified weaknesses. Throughout the
period, the inspectors frequently observed operations in the control room and
noted good professionalism and formality.
4 MONTHLY MAINTENANCE OBSERVATIONS (62703)
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The station maintenance activities addressed below were observed and
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documentation was reviewed to ascertain that the activities were conducted in
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accordance with the licensee's approved maintenance programs, the Technical
Specifications, and NRC Regulations.
4.1
Repair of SWP Control Valve
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On December 31, 1992, the inspector observed activities being performed under
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Maintenance Work Order R152757 to repair Pressure Control Valve ISWP*PC32A.
This valve controlled the service water supply to the control building
ventilation chillers.
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The inspector reviewed the work package and job plan provided to the workers
and found them to be adequate to perform the task. The technician performing
the work was qualified, as documented in the licensee's qualification matrix.
The package was approved for work, and Limiting Condition for Operation Log
Sheet LCO-92-0365 had been initiated to track the equipment and ensure that
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Technical Specification requirements were being met.
During a prework review by a quality control inspector, it was determined that
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a transistor to be replaced in the control circuit did not have sufficient
documentation to support an upgrade to a Category I component. Work was
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halted until the appropriate documentation was obtained. This was considered
a good inspection finding by the quality control inspector.
4.2 Problems with Safety-Related Valve Actuators
On January 6, 1993, the inspector identified oil leaking from the main steam
positive leakage control system Pressure Control Valve IE33*PVG022.
This
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valve utilized a Borg-Warner electrohydraulic actuator. The source of leakage
was unknown; however, the leakage was assumed to be from the hydraulic system
which was inside a sealed cover. The inspector informed the shift supervisor
of the leakage and Maintenance Work Order R174820 was initiated to report the
leak.
The inspector questioned the operability of the valve because actuator. oil
level could not be determined without cover disassembly. The shift supervisor
documented this question on Condition Report 93-0005. The system engineer
opened the inspection port on the actuator cover and verified that the oil
level was " marginally acceptable." The vendor manual stated that the
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hydraulic oil level was measured by a stem on the top of the oil reservoir and
that the stem should extend 1.2 to 1.5 inches above the top of the reservoir.
The system engineer measured the stem to be 1.25 inches. This information was
used to determine that the valve was operable.
On January 7, the inspector observed that Pressure Control Valve IE33*PVF002
was also leaking oil. On January 8, the licensee opened the inspection port
and determined that the accumulator stem was protruding less than 1.2 inches.
The operators declared the valve inoperable and entered the action statement
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requirements of Technical Specification 3.6.1.5.
Prompt Maintenance Work
Order R059392 was written to document the concern and effect the repair of the
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valve.
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On January 9, instrument and controls technicians added oil to the hydraulic
reservoir and returned the valve to an operable status.
No hydraulic leaks
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were apparent at the time.
The licensee discussed the problem of leaking hydraulic fluid with the vendor.
The vendor stated that the actuators would be capable of positioning the valve
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with only a minimal amount of fluid in the reservoir.
In addition, the vendor
stated that a small amount of oil leakage was expected from the pump shaft
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seal while the valve was operating.
The licensee determined specific criteria
for determining the operability of an actuator.
Therefore, the licensee
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stated that both Pressure Control Valves IE33*PVF022 and IE33*PVF002 had been
operable throughout this evolution.
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4.3 Repair of Pressure Control Valves
On January 11, the inspector observed portions of the repair of Pressure
Control Valve 1E33*PVF022 performed under Maintenance Work Order R174820.
The
inspector noted that the technicians were properly trained and appeared to be
knowledgeable of the actuator's function and design. A radiation survey had
been performed prior to the work.
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The quality control hold points appeared to be appropriate and were met.
The
inspector reviewed Quality Control Inspection Report 93IR20061 and determined
that good coverage of the job had been maintained. The type of oil usage was
questioned by quality control and the documentation was provided to support
its use.
The technicians inspected the actuator and found one fitting which-was less
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than wrench tight as required. The fitting was tightened and the oil
reservoir refilled to the proper level. As a postmaintenance test, the
actuator was stroked open and closed several times. The valve performed
satisfactorily and no oil leakage was observed.
The inspector reviewed the administrative controls applied to the work.
Clearance 93-I-0079-004 was implemented and walked down. The control
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operating foreman had approved the work and the work was performed under a
specific job plan. No discrepancies were noted.
In addition to the above observation, the inspector reviewed the documentation
of the work performed on January 9, 1993, to Pressure Control
Valve IE33*PVF002, under tinte ance Work Order R059392. The technicians
refilled the oil reservoir and did not find any additional problems with the
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valve.
The valve was stroked and declared operable.
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4.4 Repeated failures of Electrohydraulic Actuators
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During the observations documented in Section 4,3 above, the inspector
discussed with the craftsmen the maintenance history of this type of valve
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actuator. The craftsmen indicated that repeated failures had been identified,
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including oil leaks, electronics failures, and pressure switch failures. The
craftsmen also noted that, although the electronics cabinet had a large heat
sink and cooling fan for the transistors, the cabinet did not have any
ventilation openings, so the electronics just continued to heatup as the fan
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blew hot air inside the cabinet.
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The inspector questioned why these items had not been reviewed generally.
The
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licensee issued Condition Report 93-0007 to document and review this question.
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Licensee representatives performed a search of the maintenance work orders
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issued against these valve operators.
This search identified over
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100 corrective work orders that had been written since the plant was
licensed.
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The licensee representatives discussed the issue of the electrohydraulic
actuators with the inspectors and agreed that they have been a long-standing
problem. Two issues were addressed.
First, the maintenance problems with
these actuators was limited to valves which were continuously in service and
throttling flows. Therefore, standby valves, such as the penetration valve
leakage control system actuators, were not adversely affected.
In addition,
the control building heating, air conditioning, and ventilation valves could
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be failed open and not affect system operability. This also reduced the
impact of the maintencnce problems on the overall safety of the plant.
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Second, the licensee provided previous condition reports that indicated
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maintenance problems with the actuators were being addressed and, in fact,
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some of the problems had already been corrected.
The licensee representatives
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admitted that the overall response to the problems with these actuators could
be improved. Therefore, the licensee designated one maintenance engineer with
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the overall responsibility for these actuators in all systems.
Several
problems, including frequent failures of electronics and hydraulic oil leaks,
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continue to plague these actuators.
4.5 Conclusions
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Overall, the maintenance activities observed during this inspection period
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were good.
Repair work observed on two safety-related valve actuators was
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considered very good. A quality control inspector rejected a replacement
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electrical component which did not have sufficient documentation to suonnrt
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its qualification as Category I.
This was an example of quality assurance
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strengths at River Bend Station.
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The inspector concluded that the licensee's evaluation and corrective actions
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for maintenance problems with Borg-Warner electrohydraulic actuators was
adequate to maintain operability of affected plant safety-related systems.
The licensee's response to leaking oil in the electrohydraulic operators was
considered excellent in that the licensee promptly evaluated and corrected the
deficient conditions.
However, failure of the plant staff to self-identify
the oil leak was considered a weakness and part of an ongoing problem, which
the licensee is addressing under their response to Violation 458/92034-3.
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5 BIMONTHLY SURVEILLANCE OBSERVATIONS (61726)
The inspectors observed the surveillance testing of safety-related systems and
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components addressed below to verify that the activities were being performed
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in accordance with the licensee's approved programs and the Technical
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Specifications.
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5.1
Inservice Testing of Control Building Air Conditioning Pumps and Valves
On January 14, 1993, the inspector observed the quarterly inservice testing of
the motor-operated valves, check valves, and pump associated with the service
water recirculation loop on control building air conditioning
Chiller lHVK*CHLIC.
The test was conducted in accordance with Surveillance
Test Procedure STP-256-6321, Revision 0, " Control Building Chilled Water
Service Water Recirculation Quarterly Valve Operability and Pump Flow Test
Division
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This testing was required by ASME Code Section XI and Technical Specification 4.0.5.
The inspector reviewed STP-256-6321 for quality and adequacy and found that it
contained several typographical errors.
The errors did not impact the c H uct
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of the test because they were obvious to the trained operator.
The oper. 1
completed a comment sheet so that the errors could be corrected with a
subsequent change to the procedure.
The test instrument requirements
specified by Section 4.0 of the procedure were incomp'ute. They did not
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specify the need for a differential pressure gauge which was needed for the
check valve test of Section 7.9.
The operators acquired a differential pressure gauge with a range of
0-100 inches of water, but it was pegged high during testing and replaced
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with instrumentation that was capable of indicating the actual differential
pressure of about 10 pounds per square inch (psi). For the applicable check
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valve test, the procedure required the operator to demonstrate closure of the
check valve as evidenced by a differential pressure of zero, within 10 inches
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of water. The gauges indicated in psi, and thus could not accurately read 10
inches of water, but the operator demonstrated that the check valve had shut
because the indicated differential pressure was about zero.
This was
satisfactory for the purposes of the test.
During the pump operational test, the operator recorded pump suction pressure
to be about 53 psi when, in fact, it was about 107 psi.
The 100 psi gauge was
actually overranged and he was reading the wrong scale.
This was a two-scale
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Heise Test Gauge. When the inspector pointed out the error, the operator
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substituted a 300 psi gauge, repeated this portion of the test, and obtained
.
proper data.
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lack of electrical maintenance support when needed resulted in many hours of
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delay in the completion of the test.
When the operators first attempted to
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start the test during the previous night shift, they realized that they had no
maintenance electrical support available at all. Additional minor delays
occurred during the following day shift because of the lack of electrical
maintenance support.
This test appeared to have been poorly coordinated.
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The components under test performed well. Despite difficulties attributable
to the inexperience of the operator and minor discrepancies in the procedure,
satisfactory data was obtained and operability was confirmed.
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On January 15, the inspector reviewed the performance of this test with_
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licensee operations management, expressing concerns over the inattention given
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to the details of the procedure, including not adequately specifying the
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proper range of test equipment to be applied. The licensee responded by
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stating that there had been a transfer of responsibility from engineering to
operations to perform these inservice tests. As part of the process, the
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engineering procedures were turned over to operations and were rewritten in
the format to which the operators were accustomed.
The licensee acknowledged
,
the inspector's concerns and stated that the new inservice testing procedures
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were planned to be reviewed in detail. An "STP Proofreading Guidance"
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checklist was implemented for operations procedure changes and reviews which
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detailed commonly made errors to watch for.
It also emphasized self-checking
and attention to detail.
Consistent with this, on January 19, 1993,
Operations Policy No.12 was published implementing a self-checking program to
reduce human errors. The licensee's actions appeared to be appropriate to
address the identified weaknesses.
The inspectors will be monitoring the
results of thase efforts during future routine surveillance observations,
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The performance of the above surveillance test was indicative of possible
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weakness in the inservice testing program.
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5.2 Conclusions
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The surveillance observation consisting of the review of a new pump and valve
inservice test procedure and its implementation by the operators revealed a
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weakness. The procedure had many editorial errors indicating that a poor
validation had been performed. Also, the operators did not appear to
understand the proper use of test gauges during the test. The licensee was
already aware of the potential weakness and was taking actions to improve
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performance in this area.
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6 REVIEW OF LICENSEE PROCEDURES BASED ON AN INDUSTRY EVENT (92701)
6.1
Review of Bottom Head Pressure / Temperature Limits
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On October 16, 1992, during a cooldown of Peach Bottom Atomic Station, Unit 3,
the temperature of the reactor vessel bottom head went below the minimum
temperature / pressure values specified by Technical Specifications for assuring
!
reactor vessel integrity. This event occurre6 following a reactor scram with
,
a main steam isolation and the recirculation pumps tripped. The cause was
determined to be inadequate procedures and operator unawareness of these
4
limitations.
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The inspector reviewed the controls in place at River Bend Station to prevent
a similar occurrence. Abnormal Operating Procedure A0P-0001, " Reactor Scram,"
!
required the operator to monitor the bottom head drain temperature and reset
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the scram and any flow control valve run-back in a timely manner.
Resetting
,
the scram significantly reduces the flow of control rod drive water to the
bottom head, and resetting the flow control valve run-back helps ensure
,
natural circulation, which should help prevent stratification.
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The inspector reviewed General Operating Procedure GOP-0003, " Scram Recovery."
This procedure cautioned the operator that, if the recirculation pumps should
trip, they should be restarted on the low frequency motor generator set to
assure adequate mixing of reactor pressure vessel coolant and prevent
stagnation of cool water in the bottom head region.
This procedure further
required that, if coolant temperature to saturated steam temperature
!
differential exceeds 100oF, the operator shall depressurize the reactor
pressure vessel as necessary to maintain this differential temperature less
than 100 F.
,
The operator identified the following annunciators which would alarm to
indicate increasing reactor pressure vessel coolant differential temperatures:
Alarm No. 2003
" Reactor Water Low Temperature"
Alarm No. 2088
"RPV Dome-Bottom Drain High Diff Temp."
Alarm No. 2096
"Recirc Pump A Temp Interlod Activated"
,
Alarm No. 2105
"Recirc Pump B Temp Interlock Actuated"
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Each of these annunciators had an associated alarm response procedure which
assisted the operator in correcting this condition.
The inspector noted that System Operating Procedure SOP-0090, " Reactor Water
Cleanup System," directed the operator to ensure that the reactor bottom head
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drain isolation valve remained open at all times to provide adequate flow for
reactor pressure vessel bottom head cleanup and ten.perature detection at the
,
bottom head drain valve. Additionally, the licensee indicated numerous 'other
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procedures which addressed the maintenance of reactor coolant system pressure
and temperature limits.
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The inspector concluded that the guidance and indication to the operators was
good and that an event similar to that at Peach Bottom was not likely to occur
or go undetected at River Bend Station.
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6.2 Conclusions
The inspectors reviewed River Bend Station's design and procedural guidance
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for potential reactor vessel temperature stratification. The inspectors
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concluded that the procedural guidance provided for the operators was good and
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appeared to be effective at addressing this type of occurrence.
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7 FOLLOWUP ON CORRECTIVE ACTIONS FOR VIOLATIONS (92702)
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7.1
(Closed) Violation 458/92008-2:
Failure to Properly Establish and
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implement Surveillance Procedures Covering Refuelinq Operations
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Example A of this violation stated that the licensee's surveillance procedures
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did not fully implement the Technical Specification requirements to verify
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that at least 8 feet 2 inches of water coverage would be maintained above the
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top of the active fuel during refueling operations.
Example B stated that
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written procedures were not being properly implemented, in that a licensee
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contractor incorrectly signed that the refueling platform grapple head was at
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least 8 feet 2 inches under water when, in fact, the grapple head was more
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shallow.
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This violation was thoroughly reviewed and documented in NRC Inspection
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Report 50-458/92-08.
Preliminary corrective actions were reviewed and
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documented at that time.
During the licensee's review they determined that
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the Maintenance Lifting Procedures MLP-7504, " Fuel Handling Platform," and
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MLP-7506, " Refueling Platform Inspection and Operations," were required to
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fully satisfy the requirements of Technical Specifications 4.9.6.1 and
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4.9.6.2.
However, they were not included on the Surveillance Requirements
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Cross Reference Matrix. The inspector verified that this had been rectified.
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TN licensee agreed that the maintenance of the refueling pool water level was
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a critical step in assuring that the fuel was adequately covered at all times;
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however, this requirement was not proceduralized.
The inspector reviewed
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Alarm Response Procedure ARP-870-56, " Spent Fuel Pool Water Level High/ Low,"
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and determined that the licensee had added appropriate actions to be taken
should the alarm annunciate during refueling operations. Additionally, fuel
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handling procedures were revised to require the operator to switch to slow
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hoist speed for the final 2 feet of upward travel.
This should minimize the
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overtravel in the full up position and allow additional margin below the
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minimum pool level.
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The inspector reviewed changes to several other fuel handling procedures and
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determined that procedural controls have been provided to fully meet the
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requirements of Technical Specifications 4.9.6.1.c and 4.9.6.2.d.
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7.2
(Closed) Violation 458/9029-4:
Five Fuel Bundles Were % ; oriented When
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Refueling Procedures Were Not followed
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This violation documented that five fuel bundles were loaded in the wrong
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orientation during Refueling Outage 3.
The licensee identified the errors
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during the independent core verification and corrected the orientation. While
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refueling procedures required that core bundles be loaded in the proper
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orientation, the intent of the procedures was not clear and seemed to give
discretion to the shift supervisor on when to correct orientation errors. The
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misoriented bundles challenged the core independent verification process to
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identify and correct the errors.
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To correct the causes for this violation, the licensee clarified the
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procedural requirements for fuel movement. The licensee revised Station
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Procedure REP-0010, "Special Nuclear Material (SNM) Movement Control and
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Accounting," to add a fuel movement discrepancy form to document fuel loading
discrepancies, including miscrientation.
The licensee also added the
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requirement to verify performance of the fuel movement, including orientation,
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at the completion of the fuel movement.
The inspector reviewed Revision 8 of
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REP-0010, Temporary Change Notice 92-0437, and Temporary Change Notice 92-0644
and verified completion of the procedure enhancements.
The licensee conducted training which included the changes to
Procedure REP-0010. The inspector reviewed the lesson plan and verified that
it emphasized verifying proper orientation of the fuel bundle during each
movement and documentation of fuel movement errors on the fuel movement error
discrepancy form.
The inspector also reviewed the training attendance forms
to verify completion of the training.
7.3 1 Closed) Violation 458/9115-1:
Irradiated Fuel Was Moved in the Fuel
Handing Luildino Without the Completion of Surveillance Testina
This event involved the movement of irradiated fuel in the fuel handling
building without the performance of Surveillance Test Procedure STP-000-0103,
" Irradiated fuel Handling in fuel Building," within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of the movement
as required by Tachnical Specifications.
STP-000-0103 is a verification of
secondary containment integrity in the fuel building required prior to
handling irradiated fuel. The licensee concluded that the apparent cause for
this violation was that procedures were inadequate causing operators not to
recognize the additional surveillance requirement to demonstrate secondary
containment integrity while the plant was in Operational Condition 1.
Secondary containment was being maintained operable, as required for
Operational Condition 1, but was not demonstrated to be operable in the fuel
building within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to the handling of irradiated. fuel as required
by Technical Specification 4.6.5.2.d.
As corrective action, the licensee revised Procedures FHP-0007, "Use of Fuel
Preparation Machines," to add a prerequisite requiring secondary containment
fuel building per Technical Specification 3.6.5.2; FHP-0002, " Fuel Handling
Platform Operation," to require senior reactor operator verification of
Technical Specification requirements prior to the handling of irradiated fuel;
and REP-0010, "Special Nuclear Material (SNM) Movement Control and
Accounting," to i clude a checklist to verify Technical
Specification 3/4.6.5.2 prior to handling irradiated fuel in the fuel building
and the shift supervisor's review and approval prior to fuel handling. Also,
the licensee revised the surveillance test procedure matrix to include an
event-related item when irradiated fuel is being handled in the fuel building.
The inspector reviewed Procedure FHP-0007, Revision 4B.
Step 3.1.7 required
that secondary containment integrity in the fuel building must be established
per Technical Specification 3.6.5.2 by performing Surveillance
Test STP-000-0103 prior to the movement of any load over the spent fuel pool.
The inspector reviewed Procedure FHP-0002, Revision 4.
Step 4.4.3 required
Senior Reactor Operator verification that Technical Specification 3.6.5.2 was
satisfied.
The inspector reviewed Procedure REP-0010, Revision 8, and Change
Notice 92-0644.
Procedure REP-0010 had contained a checklist to verify
Technical Specification 3/4.6.5.2 prior to handling irradiated fuel in the
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fuel building and the shift supervisor review and approval prior to fuel
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handling, but Change Notice 92-0644 removed the procedure requirements and
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they were transferred to Procedure FHP-0001, " Control of Refueling
Operations." The inspector reviewed the surveillance test procedure matrix
and verified that it included reference to the handling of irradiated fuel in
the fuel building.
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The inspector also discussed the event with a shift supervisor, and he was
familiar with the event and the need to perform the surveillance requirement
on the fuel building even when the plant was in Operational Condition 1.
8 ONSITE REVIEW OF LICENSEE EVENT REPORTS (LERs) (92700, 90712)
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8.1
(Closed) LER 92-015: Reactor Water Cleanup System Isolation Caused by
the Failure of a Temperature Switch
This LER documents an engineered safety feature isolation of the reactor water
cleanup system when the backwash receiver High Ambient Temperature
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Monitor IE31*TSN6278 inadvertently failed.
The licensee determincd that the
root cause of the event was a combination of personnel error and equipment
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failure. At the time of the monitor failure, the reactor water cleanup system
was in " bypass" to support plant maintenance.
The operators received a common
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system alarm in the main control room; however, they assumed that the alarm
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was caused by a failed annunciator card because Monitor IE31*TSN6278 was not
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in the alarm state. Had the operators more thoroughly investigated the alarm,
this event might have been prevented.
The licensee failed to identify a specific failure mode of the temperature
switch.
The switch was replaced with a new unit and tested in accordance with
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the appropriate surveillance test procedure.
The malfunctioning unit was
returned to the equipment vendor for an in-depth analysis of the failure
mechanism.
The inspector reviewed the night order that was implemented to remind control
room operators to use all available resources to determine the cause of an
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alarm and to use extreme caution when returning a system to service following
a maintenance outage.
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8.2
(Closed) LER 92-023: Division I Diesel Generator Placed in Maintenance
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Mode for More than 1 Hour without Performing Surveillance Reauirement
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This LER documents the failure of the licensee to demonstrate the operability
of required AC power sources within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of declaring the diesel generator
inoperable. This occurred because the operators failed to realize that the
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diesel generator had been in the maintenance mode for greater than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and,
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therefore, did not perform the required surveillance precedure.
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This event was identified by the NRC and documented in NRC Inspection
Report 50- 4 b8/92-32. As a result of the review, a Notice of
Violation (458/92032-2) was issued.
lhe licensee's response to this
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.v o ai l tion, dated January 11, 1993, was more comprehensive in-corrective
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actions than the LER. The corrective actions will be tracked and closed by
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the NRC under the above violation.
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8.3
(Closed) LER 92-027:
Failure to Place the RCIC System in the Stan'dby
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Lineup
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This LER documents that the operators increased reactor vessel pressure to
above 150 psig, without first placing the RCIC system in the standby
alignment. This was in violation of Technical Specification 3.0.4.
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This event was previously reviewed, as documented _in NRC Inspection
Report 50-458/92-34. As a result of the review, a Notice of
Violation (458/92034-1) was issued.
The inspectors will review the licensee's
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response to this violation and the corrective actions will be tracked and
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closed by the NRC under the violation.
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8.4
(Closed) LER 92-028: Nuclear Instrumentation Inoperable Following Plant
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Shutdown Because Surveillance Recuirements Were Not Met
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This LER documents the licensee's failure to ensure'that the source range _and
intermediate range monitors were operable following a plant shutdown. The
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reactor was' shut down to a mode in which the instrumentation was required by
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Technical Specifications 3.3.1 and 3.3.7.6.
However, the shift supervisor _
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failed to realize that the surveillance requirements had not been met.
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This event was previously reviewed, as documented in NRC Inspection
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Report 50-458/92-34. As a result of the review, a Notice of
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Violation (458/92034-2) was issued.
The inspectors will review the licensee's
response to this violation and the corrective actions will-be tracked and'
closed by the NRC under the violation.
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8.5
(Closed) LER 92-029:
Isolation of RCIC System Valve (Indeterminate
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Cause)
This LER documents the same event as that discussed in Section 2.1 of this
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report. The licensee's actions were considered appropriate; therefore, no
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further action was determined to be required.
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8.6 (Closed) LER 91-011:
Inadeauate implementation of Surveillance
Reauirements Per Technical Specification 3/4.6.5.2 (Secondary Containment
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Integrity-Fuel Handlina) Due to Procedural Deficiencies
This LER documents the same event that was closed in Section 7.3 of this
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report.
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8.7
(Closed) LER 92-011: Missed STP for Diesel Fire Water Pump Contrary to
TS Operability Reauirement: Caused by Human Error
This LER documented a missed surveillance test for diesel fire water pump
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batteries. A routine review by the licensee on July 13, 1992, identified that
the test was overdue after July 12, 1992. The surveillance test was completed
on the morning of July 13, 1992.
The licensee concluded that the root cause
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for this event was human error. A supervisor failed to recognize that a
Sunday due date for a surveillance required additional effort to ensure
completion and a recent change in responsibility for surveillance completion
contributed to causing the occurrence. As corrective action, the licensee
conducted training for the supervisor and the electrical maintenance foreman
and started posting the surveillance test scheduling priority report in the
electrical shop.
The inspector reviewed the training attendance sheet dated October 29, 1992,
to verify completion of the training.
The inspector concluded that the
technical safety significance of this occurrence was minimal since the test
was completed satisfactorily a very shert period before the test was overdue.
The licensee's corrective actions appeared appropriate.
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ATTACHMENT 1
1 PERSONS CONTACTED
1.1 Licensee Personnel
- D. L. Andrews, Director, Quality Assurance
- J. W. Arceneaux, Nuclear Training Representative
R. E. Barnes, Superviser, Maintenance Engineering
- R. L. Biggs, Supervisor, Operations Quality Assurance
- J. E. Booker, Manager, Nuclear Industry Relations
- G. A. Bysfield, Assistant Plant Manager, Systems Engineering
- E. M. Cargill, Director, Radiological Programs
- J. W. Cook, Senior Technical Specialist
- T. C. Crouse, Manager, Administration
- W. L. Curran, Cajun Site Representative
- L. A. England, Director, Nuclear Licensing
P. E. Freehill, Assistant Plant Manager - Outage Management
E. L. Glass, Supervisor, Instrument & Control
P. D. Graham, Vice President (RBNG)
- J. R. Hamilton, Manager-Engineering
W. C. Hardy, Radiation Protection, Supervisor
M. R. High, Senior Production Safety Specialist
K. C. Hodges, Chemistry Supervisor
- G. R. Kimmell, General Maintenance Supervisor
- D. N. Lorfing, Supervisor, Nuclear Licensing
I. M. Malik, Supervisor, Operations Quality Assurance
- R. E. Northrup, Senior NSAG Engineer
- W. H. Odell, Manager, Oversight
- J. P. Schippert, Plant Manager
B. R. Smith, Mechanical Maintenance Supervisor
- J. E. Spivey, Jr. Senior Quality Assurance Engineer
- M.
A. Stein, Director
- K. E. Suhrke, General Manager, Engineering and Administration
W. J. Trudell, Assistant Operations Supervisor
R. J. Vachon, Senior Compliance Analyst
J. E. Venable, Operations Supervisor
C. W. Walker, Supervisor, Operations Quality Control
- S. L. Woody, Director, Nuclear Station Security
- Denotes personnel that attended the exit meeting.
In addition to the
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personnel listed above, the inspectors contacted other personnel during this
inspection period.
2 EXIT MEETING
An exit meeting was conducted on February 1, 1993.
During this meeting, the
inspectors reviewed the scope and findings of the report. The Manager of
Oversight committed to take corrective actions to preclude further violations
of 10 CFR Part 19.11 as discussed in Section 3.4 of this inspection report.
The licensee did not identify as proprietary any information provided to, or
reviewed by, the inspectors.
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