IR 05000416/1999012
| ML20212J821 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 09/29/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20212J818 | List: |
| References | |
| 50-416-99-12, NUDOCS 9910050316 | |
| Download: ML20212J821 (14) | |
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ENCLOSURE U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
l Docket No.:
50-416 License No.:
NPF-29 Report No.:
50-416/99-12 Licensee:
Entergy Operations, Inc.
Facility:
Grand Gulf Nuclear Station Location:
Waterloo Road Port Gibson, Mississippi 39150 Dates:
July 25 through September 4,1999 Inspector (s):
Jennifer Dixon-Herrity, Senior Resident inspector Peter Alter, Resident inspector Approved By:
Joseph Tapia, Chief, Project Branch A ATTACHMENTS: Supplemental Information l
9910050316 990929 PDR ADOCK 05000416
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EXECUTIVE SUMMARY Grand Gulf Nuclear Station NRC Inspection Report No. 50-416/99-12 This inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a 6-week period of resident inspection.
Operations Operator inattention to detail and poor procedural guidance resulted in inadequate tie
wrap seals on throttled Division I and 11 standby diesel generator standby service water
cooler outlet valves. The valve position could be changed without breaking the tie wrap.
The valves were in the correct throttled position. The licensee reinstalled the sealing devices on the valves to ensure they remained in their proper throttled position and planned to revise the procedural guidance for locked valves (Section O2.1).
The main steam isolation valve leakage control system was correctly aligned and
maintained in good material condition (Section O2.2).
Maintenance The ten maintenance and testing activities observed were properly performed. Fireproof
fabric scraps left on a scaffold over the suppression pool and the dropping of a sheet of fireproof fabric into the pool were exampler., inere the housekeeping and foreign material exclusion in a work area could be better controlled (Section M1.4).
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The inspectors identified three examples where limited corrective actions were taken
and resulted in missed opportunities for the licensee to identify and correct problems.
The examples included: (1) a procedural problem with the operation of the diesel driven fire pumps which resulted when one condition report was closed by referencing a similar condition report without addressing differences between the two (Section F3.1);
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(2) degraded seals on three high energy line break doors were not identified after recognizing that there was no inspection program for the seals, and similar problems and inadequate preventive maintenance for flood door seals had been identified the year before (Section E2.1); and (3) operators had not received training on the changes to the acceptance criteria and procedural guidance for the reactor core isolation cooling system turbine oil level (Section M1.2).
The failure to address the cause for the failure of the standby service water stop check
Valve P41F169B identified in Condition Report CR-GGN-1998-740 was identified as a
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violation of 10 CFR Part 50, Appendix B, Criterion XVI. This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is captured in the licensee's corrective action program as Condition Report CR-GGN-1999-802. The licensee subsequently repaired the valve (Section E2.3).
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The engineering modification to cut Train A standby service water instrument lines and
abandon them in place was technically sound (Section E2.2).
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Plant Support Observed activities involving radiological controls were well performed. The inspectors
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identified one situation where the posted area boundaries were unclear, indicating a need for closer attention to detail in posting areas and documenting surveys (Section R1.1).
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Reoort Details j
Summarv of Plant Status
.The plant operated at'100 percent power throughout the inspection period.
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1. Operations
Conduct of Operations 01.1 General Comments (71707)
The inspectors performed control room observations to assess operator knowledge and performance. Operations shift turnovers and shift briefs were thorough and well conducted. Operators were knowledgeable of the status of equipment, and applicable Technical Specification limiting conditions for operations were appropriately entered.
The inspectors observed as operators responded to a radial well pump trip on September 2,1999. The operators' response was prompt and well controlled.
Operational Status of Facilities and Equipment O2.1 Plant Tours a.
Insoection Scope (71707)
The inspectors conducted tours through safety-related portions of the plant.
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Observations and Findinos The areas of the plant that were toured were maintained in good condition. While conducting the tours, the inspectors observed that the door seals at the base of the doors to residual heat removal Trains A and B pump rooms had degraded to the point that the rubber portion of the seal did not lower down out of the seat casing, leaving a gap as large as a half-inch at the base of the door. The seal was designed to extend from the seal casing and rub the floor to contain the energy released from a high energy line break in the room. The corrective actions taken to address the deficiency are discussed in Section E1.1 of this report.
On August 18,1999,' the inspectors observed that the Division I and il standby diesel generator standby service water cooler outlet Valves, P41-F023A and P41-F023B, were inadequately sealed with tie wraps. The inspectors informed the plant supervisor and reviewed Procedure 04-1-01-P41-1," Standby Service Water System," Revision 107, Procedure 01-S-06-2, " Conduct of Operations," Revision 107, and Procedure 02-S-01-2,
" Control and Use of Operations Section Directives," Revision 31. The inspectors questioned whether the tie wraps could be removed and replaced without breaking the
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tie wrap. The plant supervisor found that he could remove the tie wraps from the gear boxes without breaking them. The valves were then securely tie wrapped in place.
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Procedure 04-1-01 P41-1 required that the valves be sealed in specific throttled positions. The licensee's locked components guidelines in Procedure 01-S-06-2 required that red tie wraps of a substantial material be placed on throttled valves to
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-2-indicate that the valve was throttled. The inspector observed that the procedure did not define the purpose of sealing or locking the valve unless the valve was a chain-operated valve. The licensee documented the discrepancy in CR-GGN-1999-0908 and planned to revise the guidelines to ensure that tie wraps were installed so that the valve's position could not be changed without breaking the tie wrap.
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Conclusion Operator inattention to detail and poor procedural guidance resulted in inadequate tie wrap seals on throttled Division I and ll standby diesel generator standby service water cooler outlet valves. The valve position could be changed without breaking the tie wrap.
The valves were in the correct throttled position. The licensee reinstalled the sealing devices on the valves to ensure they remained in their proper throttled position and planned to revise the procedural guidance for locked valves.
O2.2 Enaineered Safety Feature System Walkdown a.
Inspection Scope (71707)
The inspectors conducted daily control board walkdowns to verify that engineered safety feature systems were aligned as required by Technical Specifications for the existing operating mode, that instrumentation was operating correctly, and that power was available. The inspectors performed a more detailed walkdown of accessible portions of the main steam isolation valve leakage control system to independently verify its operability and configuration. During this review, the inspectors reviewed Instruction 04-1-01-E32-1, " Main Steam Isolation Valve Leakage Control System,"
Revision 24, and P&lD M-1097, " Main Steam Isolation Valve Leakage Control System -
Unit 1," Revision 16.
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_ Observations and Findinas Equipment operability, material condition, and housekeeping for the main steam
' isolation valve leakage control system were well maintained. The inspectors verified that the system was properly aligned for the existing mode of operation. The inspectors reviewed the maintenance records and the system engineer's quarterly status and found that there were no significant maintenance concerns open for the system.
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Conclusions The main steam isolation valve leakage control system was correctly aligned and maintained in good material condition.
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' Quality Assurance in Operations 07.1 Licensee Self Assessment Activities (71707)
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The inspectors reviewed multiple licencee self-assessment activities, including one plant safety review committee meeting, one meeting of the corrective action review board, numerous condition review group meetings, and reviewed the condition reports
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generated during the inspection period. The inspector determined that the effects on
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plant safety and reportability were correctly evaluated and that the need for a root cause determination was identified where required by procedures. During the meetings attended, the members exhibited a good understanding of the concerns addressed and asked pertinent questions. The corrective actions taken in response to condition reports j
were at times limited and untimely. This observation is addressed in Section E2.3. The inspectors concluded that the self-assessment activities observed were adequate, 11. Maintenance
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i M1 Conduct of Maintenance M1.1 Maintenance and Surveillance Observations a.
Inspection Scope (62707. 61726)
The inspectors observed all or portions of the maintenance and surveillance activities listed below. For surveillances, the test procedures were reviewed and compared to the Technical Specification surveillance requirements and bases to ensure that the procedures satisfied the requirements. Maintenance work was reviewed to ensure that adequate work instructions were provided, that the work performed was within the scope of the authorized work, and that the work performed was adequately documented. In all cases, the impact to equipment operability and applicability of Technical Specifications actions were independently verified. The following are the maintenance action items (MAls) and surveillance tasks observed:
Maintenance:
250948 Control blade processing
8/10/99 Oil addition to the reactor core isolation cooling turbine a
211889 Replace Division ill 125 vde battery
258521 Replace high pressure core spray diesel Engine A jacket water
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heater 262298 Replace high pressure core spray diesel Engine A jacket water
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outlet temperature switch 263350 Flush standby liquid control suction piping i
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06-OP-1E51-0-0003 [ Reactor Core Isolation Cooling] RCIC System Quarterly
Pump Operability Verification 06-OP-1P75-R-0004 Standby Diesel Generator 1218-Month Functional Test
06-EL-1 L11-O-0001 125 vde Battery Bank All Cell Check
06-OP-1C41-M0001 Standby Liquid Control Operability
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Observations and Findinas The inspectors observed that the work performed during these activities was well conducted. With one exception, the operators and maintenance technicians were experienced and knowledgeable of their assigned tasks and of equipment performance.
The inspectors observed that operators were not aware of why the RCIC turbine oil was required to be verified at the required level. This observation i.s discussed in
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Section M1.2. Good coordination between the control room operators and operators and technicians in the field resulted in effective performance of the surveillance tests.
M1.2 Guidance on Oil Levelin RCIC Turbine On August 10,1999, the inspectors observed as auxiliary operators prepared to run the RCIC turbine-driven pump for the quarterly surveillance. Operators started the gland seal compressor, as required by the procedure, and observed that the pressure gauge did not increase to the pressure required in the procedure. After attempting to adjust the pressure, operators concluded that there was a problem with the gauge and planned to initiate an mal to repair it. The inspectors later found that there was already an MAI in place for the problem. The inspectors discussed this with the operations superintendent. It was not the operator's practice to check for open MAls prior to starting a surveillance, and the existing MAI program did not require that a tag be aung on equipment. The superintendent acknowledged the limitation in their program ard planned to review it to determine whether their way of documenting deficiencies should be changed.
After the operators had completed the step for starting the compressor, the inspectors observed that the oil level on the turbine oil gauge was below the required level and questioned the operators. The operators explained that they checked the oil level before starting the compressor, as required by the procedure, and that it had been close to the limit, but was still acceptable. The inspectors indicated that it was now 1/8-inch below the limit. The lower limit was set due to the limitations of the shaft driven oil pump. During turbine startup and shutdown, the shaft-driven pump was not able to provide the necessary lubrication for the shaft bearings. To compensate for this, the manufacturer had installed a slinger ring. Below the low level mark, the ring would not dip in the oil well adequately to lubricate the bearing. The inspectors found that the j
operators were not aware of the reason for the level acceptance criteria and were confused as to why the acceptance criteria had changed several times in the past year.
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in NRC Inspection Reports 50-416/98-08 and 99-08, the inspectors identified concerns i
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with the control of the turbine oil level and inconsistencies in the procedures dealing with the turbine oil level. The procedures had been revised so that guidance was consistent.
However, through discussion with the operators, the inspectors found that no training i
had been provided to the operators to explain how the oil system worked or why the acceptance criteria had changed numerous times in the last year. The inspectors discussed the change in the acceptance criteria for the oil level and the operator's misconceptions about the numerous unexplained changes in the acceptance criteria for the turbine oil level with the operations superintendent. After discussing the concern with operations personnel, the superintendent explained that personnel were aware of
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the acceptance criteria, but planned to provide on-shift training on the past changes. In reviewing the system, the inspectors observed that the oil system had been filled approximately four times in the past 5 weeks. The inspectors discussed this concern with the operations superintendent and the superintendent initiated CR-GGN-1999-1032. The remainder of the test went well.
M1.3 Replacement of Valve P41F169B During the night shift on September 2,1999, the inspector toured the job site where Valve P41F169B had been removed from the system. The licensee was preparing to reinstall the valve. Because the valve was located in the overhead, scaffolding was built to allow access to the area. At the end of the previous day, maintenance personnel had prepared the work area for welding. This included cutting up and laying out fireproof blankets around the valve. The inspector observed that no precautions had been taken to prevent material from falling from the scaffolding through the floor grating and into the suppression pool. The fabric scraps and threads from the previous day were laying on the scaffold floor and several had fallen into the pool. The inspectors discussed this concern with the superintendent. During the morning meeting, the inspectors found that the mechanical maintenance personnel documented that they dropped a sheet of fireproof fabric in the pool when they started work that morning. The fabric was i
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removed from the pool and the occurrence was documented in Condition Report CR-GGN-1999-101.
M1.4 Conclusions on Conduct of Maintenance The ten maintenance and testing activities observed were properly performed. Fabric scraps left on scaffolding over the suppression pool and a sheet of fireproof fabric falling into the pool were examples where the housekeeping and foreign material exclusion in a work area could be better controlled. The corrective actions for a previously identified deficiency regarding the reactor core isolation cooling system turbine oil level were
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Ill. Enaineerina E2 Engineering Support of Facilities and Equipment E2.1 Dearaded Hiah Enerav Line Break Door Seals a.
Inspection Scope (37551)
The inspectors reviewed the history and the licensee's response to the deficient door seals discussed in Section O2.1.
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Observations and Findinas Engineering personnel informed the inspectors that a condition report (CR) had already been opened on the discrepancy. The inspectors reviewed CR-GGN-1998-1069. The CR documented that during an audit performed on October 7,1998, personnel identified that there was a potential problem in that there was no inspection program for the door seals on high energy line break doors. Although corrective actions were taken to develop an inspection for the door seals, no action was identified to verify the condition of the door seals. The door seal inspection task was not due to be completed until December 31,1999. There were nine doors of this type onsite. An engineering review was conducted to identify the significance of the failure to include the door seals in the preventive maintenance program. The review concluded that there was limited concern because the door seat leakage would not increase the nonharsh environment temperature. The inspectors noted that the review did not address the effect of the leakage on the associated standby gas treatment system train performance.
Engineering personnel verified that the limited amount of leakage would have little effect on the efficiency of the standby gas system.
The inspectors recalled that there had been other opportunities to question the condition of the door seals. In NRC Inspection Report 50-416/97-12, the inspectors identified that no preventive maintenance was being pedormed on seals on exterior doors used for flood control. The corrective actions for the CR generated (CR-GGN-1997-772) at that time addressed the exterior doors, but did not question the condition of other safety-related door seals onsite.
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Conclusions The licensee failed to identify degraded seals on three high energy line break doors after identifying that they did not have an inspection program for the seals and had identified similar problems and inadequate preventive maintenance for flood door seals the year before.
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' E2.2 Cut and Abandon Standbv Service Water Instrument Line.
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- Insoection Scope (37551)
The inspectors reviewed Engineering Request 99/0066,L" Modification to OSP41-FE-N081 A and B instrument Piping," and Change Notice No.1999-0048.
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Observations and Findinos After identifying a through-wall piping leak on a Train B standby service water instrument line early in 1999, Engineering personnel found that the system flow test
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would be more effective with a full flow test, which would allow the degraded instrument
,line to be removed and the remainder to be abandoned in place. This modification was
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completed in February 1999. At that time, a design change package was prepared for both trains. The Train B instrument line was cut and threaded to allow it to be instrumented to provide baseline test data for the new test. After the test, the Train B instrument line was capped and abandoned in place. Soon after the licensee completed the work on Train B, they used the undamaged existing line on Train A to collect similar
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data to allow the Train A instrument line to be removed at the next outage. On a
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August 24,1999, the licensee identified that the Train A instrument line had degraded and was leaking during the partial flow test of the standby service water system.
The safety evaluation and the interim design change package were complete and adequately addressed the deficiency. The lines were off of the minimum flow bypass
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line and would be normally isolated during system operation. The line was successfully cut and the remainder of the pipe was abandoned.
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Conclusions
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. The engineering modification to cut Train A standby service water instrument lines and -
abandon them in place was technically sound.
E2.3. Repeat Failure of Valve P41F169B to Pass Surveillance a.
- Inspection Scooe (37551)
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The inspectors reviewed the history of problems with drywell purge Compressor B standby service water stop check Valve P41-169B and attended meetings addressing
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. Valve P41-1698, a containment isolation valve that would normally remain open'during
. an accident, failed to close during Surveillance 06-OP-1P41-0 0005,"SSW Loop B Valve an' Pump Operability Test," Revision 104, on August 2,1999. The valve failed d
similar tests on May 14,1999, June 24,1998, and June 22,' 1995. In 1995, the valve was cleaned,- retested, and returned to' service, in 1998, CR-GGN-1998-740 was
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-8-identified two potential causes for the failure. The first was dirt and sludge in the valve preventing the valve disc from closing, and the second was that the valve was installed
with the bonnet of the valve in the horizontal position as opposed to the vertical position.
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The CR also documented that the horizontal installation did not allow the valve to close
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by the weight of the disc along with gravitational force, as designed. A reverse flow would have to occur to assist the valve closing. Only the first cause was addressed in CR-GGN-1998-740.
In June 1998, a tagging error during the work on Valve P41F169B resulted in two containment isolation valves being left open without administrative controls. Due to the three maintenance preventable functional failures (two tagging errors and the Valve P41F1698 failure), the containment integrity system was placed in (a)(1) status under the Maintenance Rule and CR-GGN-1998-878 was generated. One of the corrective actions for this CR required engineering to take corrective actions to preclude recurrence of the valve failure. The engineering response to this action was the same as that to CR-GGN-1998-957, which documented a concern on the slow closing of Valve P41F169A. Valve P41F169A closed during its surveillance and, unlike Valve P41F1698, was installed correctly. The corrective action taken for CR-GGN-1998-957 was to change the internal inspection frequency from once every 10 years to once every 3 years to allow closer monitoring for valve degradation. The licensee cleaned Valve P41F169A, conducted a satisfactory test, and planned to take no further action unless the valve failed again.
In response to the test failure in May 1999, CR GGN-1999-526 was generated, the valve was cleaned, the internals were replaced, and Engineering Request 1999/0223 was
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generated to look at the problem. CR-GGN-1999-526 was closed after the engineering request was generated. As of August 2,1999, no action had been taken in response to the engineering request. After the fourth failure on August 2,1999, the licensee researched the problem and developed a design change to move a hanger above the valve and rotate the valve. The licensee rotated the valve, but the valve did not close adequately to pass the surveillance test after it was rotated because of degradation due to corrosion within the valve. The licensee replaced the valve and tested it satisfactorily.
The inspectors observed that the problem was initially identified in 1995 and defined in June 1998. No action was taken on the problem for over a year, even though two potential causes were identified in CR-GGN-1998-740, and the system was being tracked as a(1) under the Maintenance Rule. CR-GGN-1998-878 required that action be taken to prevent recurrence. The licensee explained that although the valve was a containment isolation valve, it was required to be open during an accident to allow cooling water flow to reach the drywell purge compressor. The line was not part of the reactor pressure boundary or directly connected to the containment atmosphere.
Engineering personnel suggested that the line should have been designed under 10 CFR Part 50, Appendix A, Criterion 57, instead of Criterion 56. In this case, the valve would not be required. The valve was tested quarterly and passed the l
surveillance test three times after the June 1998 failure. Given this information, the inspectors determined that the risk significance of * ') valve failure was very low.
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assure that conditions adverse to quality, such as deficiencies and nonconformances, i
are promptly identified and corrected. The identified cause of the valve failure was not addressed for over a year and until the valve had failed two additional times. The valve
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was placed in (a)(1) tracking for the Maintenance Rule, but no additional emphasis was placed on the repeat failure. The failure to address the apparent cause identified in CR-GGN-1998-740 promptly or to take corrective action for the failure of Valve P41F169B was an example of inadequate corrective action and a violation of 10 CFR Part 50,' Appendix B, Criterion XVI. This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy (50-416/9912-01). This violation is captured in the licensee's corrective action program as CR-GGN-1999-802. The licensee subsequently repaired the valve.
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Conclusions The failure to address the cause for the failure of the standby service water stop check Valve P41F169B identified in CR-GGN-1998-740 was identified as a violation of 10 CFR Part 50, Appendix B, Criterion XVI. This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is captured in the licensee's corrective action program as CR-GGN-1999-802.
The licensee subsequently repaired the valve.
IV. Plant Support i
R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 ~ Control Rod Blade Disoosal a.
Inspection Scoce (71750)
The inspectors conducted tours of the safety-related areas and observed radiation protection activities.
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Observations and Findinas During tours of the radiologically controlled area, the inspectors observed radiological postings and worker adherence to radiation protection procedures. Personnel followed radiation protection procedures and locked high radiation area doors were locked. The inspectors observed the controls and postings in place during the processing of control rod blades removed during the previous refueling outage. The inspectors reviewed Radiation Work Permit 99-06-01 and the safety evaluations conducted prior to starting the work and observed one job brief. The documentation for the activity was complete.
The job brief was detailed, and those involved were knowledgeable of the work and provided constructive input during the brief.
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While observing this work, the inspectors found that the high contamination area posting l
was unclear. The way that the area was being used was not reflected in the area posting or on the survey map. The spent fuel pool and cask wash down area were normally posted as a high contamination area. During the work, the rop 6 across the bridge was down, and personnel were treating the bridge area like a contamination area. The inspectors discussed the observation with the radiation protection technicians i
in the area. The technicians explained that the bridge area between the pool and the cask wash down area had been made a contamination area to facilitate work in the
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area. The contamination levels were appropriate to post the area as a contamination I
area. The inspectors discussed the posting in the area with radiation protection management. The managers indicated that the method used to post the area did not meet their expectations and planned to have the area clearly posted so as to prevent confusion.
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Conclusions Observed activities involving radiological controls were well performed. The inspectors identified one situation where the posted area boundaries were unclear, indicating a need for closer attention to detail in posting areas and documenting surveys.
P8 Miscellaneous Emergency Preparedness issues (92904)
P8.1 (Closed) Insoection Followuo item 50-416/9816-02: Lack of Procedural Guidance for Evacuee Destination. This issue involved a lack of guidance in the procedures for the provision of destination options when announcing the need to evacuate to the site. The inspectors observed that this information was provided during the site evacuation announcement made during the drill held on June 23,1999. In addition, the inspectors found that the emergency director's checklists provided in the control room and technical support center were revised to require that this information be provided during the announcement prior to the drill. The inspectors reviewed Procedure 10-S-01-11,
" Evacuation of Onsite Personnel," Revision 13. The procedure was revised on August 13,1999, to include the requirement to select the appropriate evacuation route, with the available options listed, if a release was in progress and to include that information in the announcement.
F3 Fire Protection Procedures and Documentation F3.1 Unexoected Start of Diesel Driven Fire Pumo B a.
Insoection Scoce (71750)
During restoration of the diesel driven fire Pump B following maintenance activities, the diesel started unexpectedly. The inspectors reviewed Instruction 04-S-01-P64-1, " Fire Protection Water System," Revision 38, and previously issued condition reports for similar events during the restoration of diesel driven fire Pump A in November and December 1998.
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Observations and Findinos On August 28,1999, diesel driven fire Pump B started unexpectedly while operators were restoring the pump to service following maintenance. The operators were following Instruction 04-S-01-P41-1 for placing the diesel driven fire pumps in the standby mode of operation. The operators determined that these instructions were inadequate and restored the fire pump to standby using the procedure's instructions for rt%?ning the pump to standby following a manual or automatic start. The operators wrote CR-GGN-1999-0969 to describe the situation. The operations assistant consulted with the system engineer and planned to revise that portion of the procedure for placing the diesel driven fire pumps in the standby condition.
The inspectors reviewed CR GGN-1998-1486, which documented a similar event during the restoration of diesel driven fire Pump A in December 1998. This condition report was closed to CR-GGN-1998-1419, which documented another problem with diesel driven fire Pump A in November 1998, in November, Pump A had also started during restoration from maintenance, but in that case the problem was traced to a sticking test solenoid. The situations in December 1998 and on August 28,1999, were more closely related. When questioned by the inspectors, a member of the corrective action quality review group stated that the responsibility for determining that a condition report can be closed by the corre.tive actions for another condition report lies with the condition
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review group when they close a condition report to the other condition report. The inspectors determined that the corrective actions for CR-GGN-1998-1419 did not resolve the problem identified in CR-GGN-1998-1486. The inspectors noted that this was a missed opportunity to change the system operating instruction and avoid the unexpected start of diesel driven fire Pump B on August 28,1999, c.
Conclusions
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i The licensee missed an opportunity to resolve a procedural problem with the operat;on of the diesel driven fire pumps when they closed one condition report by referencing a j
similar condition report and failing to address differences between the two.
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S1 Conduct of Security and Safeguards Activities (71750)
On a daily basis, the inspectors observed the practices of secuny personnel and the
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condition of security equipment. Protected and vital area barriers were in good condition. The isolation zones were free of obstructions, and the protected area illumination levels were good. Compensatory actions were taken as necessary for systems that were taken down for maintenance. The inspectors concluded that the daily security activities were conducted in a professional manner.
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12-V. Management Meetinos X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on September 3,1999..The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary.- No proprietary information was identified.
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-13-ATTACHMENT 1 PARTIAL LIST OF PERSONS CONTACTED Licensee C. Bottemiller, Manager, Plant Licensing
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R. Carroll, Suparintendent, Operations
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D. Cupstid, Manager, Operations Technical Support B. Edwards, Manager, Planning and Scheduling C. Elisaesser, Manager, Corrective Action and Assessment C. Lambert, Director, Design Engineering i
J. Roberts, Director, Quality Programs C. Stafford, Manager, Plant Operations J. Venable, General Manager, Plant Operations R. Wilson, Superintendent, Radiation Protection NRC
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P. Sekerak, NRR Project Manager I
INSPECTION PROCEDURES USED 37551 Onsite Engineering 61726 Surveillance Observations 62707 Maintenance Observation 71707 Plant Operations 71750 Plant Support Activities 92904 Followup - Plant Support ITEMS OPENED. CLOSED. AND DISCUSSED Opened 50-416/9812-01 NCV Untimely corrective actions for failure of Valve P41F169B (Section E2.3)
Closed 50-416/9812-01 NCV Untimely corrective actions for failure of Valve P41F1698 (Section E2.3)
50-416/9816-02 IFl Lack of Procedural Guidance for Evacuee Destination (Section P8.1)