IR 05000382/1999016

Insp Rept 50-382/99-16 on 990704-0814.Noncited Violations Noted.Major Areas Inspected:Operations,Maintenance, Engineering & Plant Support

ML20211K987
Person / Time
Site:	Waterford
Issue date:	09/01/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20211K977	List: IR 05000382/1999016 ML20211K974
References
50-382-99-16, NUDOCS 9909080121
Download: ML20211K987 (23)

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ENCLOSURE U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket No.: 50-382 License No.: ' NPF-38 Report No.: 50-382/99-16 Licensee: Entergy Operations, In Facility: Waterford Steam Electric Station, Unit 3 Location: Hwy.18 '

Killona, Louisiana Dates: July 4 through August 14,1999 Inspectors: T. R. Farnholtz, Senior Resident inspector J. M. Keeton, Resident inspector R. Bywater, Senior Resident inspector, Arkansas Nuclear One

. Approved By: P. Harrell, Chief, Project Branch D ATTACHMENT: Supplemental Information I

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9909000121 990901 PDR ADOCK 05000382 O PDR 4

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EXECUTIVE SUMMARY Waterford Steam Electric Station, Unit 3 NRC Inspection Report 50-382/99-16 Operations

The licensee's actions regarding an indication of loss of charging flow with two charging pumps running were appropriate. The cause of the problem was determined to be a failed flow transmitter, which was subsequently replaced and satisfactorily tested. The licensee's investigation of this event was effective and comprehensive (Section O2.1).

Operator actions to initiate a manual reactor trip following indications of a failed reactor coolant pump seal were appropriate. Conditions following the trip were as expecte Operator actions to control reactor coolant system temperature immediately following the reactor trip were appropriate and timely. In general, operator actions were effective while placing the plant in the required configurations to allow maintenance activities to be performed (Section O4.1).

The control room operators performed the draindown of the reactor coolant system in a safe, well-controlled, and effective manner (Section 04.2).

• A violation was identified for exceeding the maximum Technical Specification cooldown rate for the reactor coolant system. The violation had not been identified by the licensee prior to questioning by the inspectors. Operators did not maintain an adequate ,

awareness of changing plant conditions. A subsequent engineering evaluation indicated I

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that the reactor coolant system integrity had not been compromised. This Severity Level IV violation is being treated as a noncited violation consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as Condition Report 99-0828 (Section O4.3).

• During a reactor and plant startup, the operators conducted these activities in a controlled manner. Management oversight of the control room activities was continuously maintained (Section 04.4).

Maintenance

Two examples of lack of attention to detail and lack of concern for creating a complete and accurate record of work performed on safety related equipment were identifie Maintenance technicians failed to sign off procedural steps upon completion of work on the condenser of Essential Chiller B, and a checklist to be used during the prejob briefing was not utilized (Section M4.1).

Enaineerina

A violation was identified for the failure to meet the requirements of the licensing basis I

for two rainfall accumulation events with regard to the ultimate heat sink sump Several nonconservatisms were identified by the licensee in the original calculation, i which when taken together indicated that additional pumping capacity was required to remove the accumulation of two analyzed rainfall events. The initial operability l

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-2-determination for the ultimate heat sink was considered adequate. The initially stated time frame to install additional pumping capacity in the sumps was exceeded due to an apparent decrease in the urgency of this effort. This Severity Level IV violation is being treated as a noncited violation consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as Condition ,

Report 99-0789 (Section E1.1).

The licensee's efforts to establish the root cause of the seal failure, which forced a plant shutdown, were considered good. A Significant Event Response Team was well organized, focused, and provided reasonable recommendations based on sound engineering. A cracked seal water heat exchanger baffle was identified as the cause of the seal failure. The preliminary cause of the crack was identified as fatigue. A new 1 baffle was installed in the same configuration as was used 3 years earlier and additional '

examinations and modeling were planned (Section E2.1).

Plant Support  !

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Radiological protection personnel demonstrated a good level of knowledge and utilized innovative and effective metnods to monitor the reactor coolant pump seal replacement job. The containment building condition was considered adequate (Section R1.1).

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The actions of site security personnel were considered unprofessional and I demonstrated a lack of rigor and lapses in attention to detail. Several examples of I informal radio, face-to-face, and written communicatico techniques were observed. The presence of unauthorized reading material at a watch station was an example of low standards and expectations for the performance of official duties (Section S4.1).

Security officers involved in an event in which a plant employee had difficulty accessing the protected area were confused and demonstrated a lack of attention to detail Ineffective communication techniques contributed to the level of confusion and on-scene security officers failed to take positive control of the situation. Security officers failed to i ensure that the turnstile was in the proper mode of operation to allow access to the protected area (Section S4.2).

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Summary of Plant Status l

At the beginning of this inspection period, the plant was operating at 100 percent power. On

August 1,1999, operators initiated a manual reactor trip in response to indications of Reactor

Goolant Pump (RCP) 28 seal failure. Repairs were made to the seal assembly and a reactor

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startup was conducted on August 10. The plant reached full power on August 11 and remained at that level for the remainder of this inspection perio . Operations 01' Conduct of Operations (71707) .

01.1 General Comments (71707)

The inspectors performed frequent reviews and observations of ongoing plant operations, control panel walkdowns, and plant tours. Observed activities were performed in a manner consistent with safe operation of the facility. The inspectors observed operators utilize good self-checking and peer-checking techniques when I manipulating plant equipment. Operators generally used good communication techniques, j

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02 Operational Status of Facilities and Equipment 1 O2.1 Indications of Loss of Charaina Flow with Two Pumps Runnina Inspection Scoce (71707)

The inspectors reviewed the licensee activities following an operator observation that indication of total charging flow went to zero with both Charging Pumps A and B runnin Observations and Findinas  !

. On August 2,1999, during plant _cooldown and depressurization activities, the control !

room operators noted that the indicated total charging flow was zero with Charging ;

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Pumps A and B operating. Expected flow in this condition should have been 88 gp At the time, reactor coolant system (RCS) pressure was approximately 350 psi.

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Operators secured Charging Pump A and noted that flow indicated 44 gpn as would be expected with one charging pump (Pump B) running. A plant operator was dispatched to the Charging Pump A room to observe localindications. The control room operators then restarted Charging Pump A and observed the charging flow rate go to zero. The local operator stated that he felt that the Pump A relief valve was lifting and passing flow l when the pump was restarted. The operators secured the pump and declared it i

inoperabl The licensee assembled a team to investigate this event. The Charging Pump A relief valve was removed from the system and tested. Results of this test indicated that the

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. i relief valve lifted within tolerance and reseated, as required. No problems were found with the valve. The valve was reinstalled in the system. Preparations were made to cut out and remove the Charging Pump A discharge check valve to determine if it was functioning properly. Before this work was performed, the licensee conducted an additional test of the system by running the pumps in parallel to attempt to replicate the problem. Results of this test indicated a potential problem with the flow transmitte Further investigation revealed that the flow transmitter was not functioning properly and that this was the cause of the observed flow anomalies. The flow transmitter was replaced and tested catisfactorily. The inspectors considered the licensee's t investigation of this event to have been effective and comprehensiv This event had similar indications to an event, which occurred on June 6,1996. At that time, it was noted that total charging flow went to zero when a second charging pump was started for surveillance testing. The cause of this event was determined to be a low setpoint on the relief valve for Charging Pump AB and a degraded pulsation damper on Charging Pump AB. Corrective actions were taken and the system returned to operable status. When the August 2 event occurred, consideration was given to a possible j repeat of the 1996 event. However, investigation revealed that the causes were different and that adequate corrective actions were taken in both case Conclusions The licensee's actions regarding an indication of loss of charging flow with two charging pumps running were appropriate. The cause of the problem was determined to be a failed flow transmitter, which was subsequently replaced and satisfactorily tested. The I licensee's investigation of this event was effective and comprehensiv Operator Knowledge and Performance i

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04.1 Manual Reactor Trio Due to RCP Seal Failure l a. Inspection Scope (71707. 93702)

The inspectors observed operator actions and reviewed plant response following a l

manual reactor tri b. Observations and Findinas On August 1,1999, at 9:49 p.m., control room operators initiated a manual reactor trip when indications of seal failure on RCP 2B were noted. An alarm on the plant monitoring computer indicated that the middle seal pressure was low on RCP 28. Also, the controlled bleedoff flow indicated low, and the controlled bleedoff temperature indicated high. Based on these indications, the operators determined that seal failure had occurred and took the action to trip the plant and secure RCP 2B. The inspectors considered this decision to be appropriate. No indicativis of RCS leakage from the failed seal were noted before or af ter the manual reactor trip.

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I Conditions after the trip were as expected. All systems functioned, as designed. An automatic actuation of the emergency feedwater system occurred when steam generator levels fluctuated. However, the emergency feedwater system was not required to feed the steam generators because the main feedwater pumps remained in operation and the main feedwater system continued to function. The control room operators secured unnecessary steam loads in a timely manner to maintain RCS temperature. One main feedwater pump was secured and manual control of steam generator water levels was initiated. The inspectors noted that the operator experienced some difficulty maintaining steam generator water levels within the required band since the feed rate was at a minimal level and the system was not optimized for the low feed rate. When plant conditions allowed, the operators started the auxiliary feedwater pump and secured the remaining main feedwater pump. This allowed better control of the water levels. The inspectors concluded that these actions were appropriate and timel The licensee determined that the RCP seal would require replacement and associated components would need to be inspected and repaired, as required. To perform these activities, the plant was placed in Mode 5 and the RCS water level drained to a level in the range of 14.4 to 14.8 feet. The inspectors observed these activities and determined that, in general, the operators were deliberate and cautious in their actions. However, RCS cooldown rate requirements were exceeded during the process of placing the plant in a condition to allow RCP seal repairs. Details of this event are contained in Section O4.3 of this repor On August 7, the operators commenced filling and venting the RCS after completion of the RCP repairs. No concerns were identified. Details of the seal failure and actions taken to repair the seal and associated components are contained in Section E2.1 of this repor Conclusions Operator actions to initiate a manual reactor trip following indications of a failed RCP seal were appropriate. Conditions following the trip were as expected. Operator actions to control RCS temperature immediately following the reactor trip were appropriate and timely. In general, operator actions were effective while placing the plant in the required configurations to allow maintenance activitics to be performe .2 RCS Draindown for RCP Maintenance Insoection Scope (71707)

The inspectors observed control room operators drain the RCS inventory in preparation for RCP seal maintenance from near the bottom of the prcssurizer to approximately 1 foot above hot leg centerline using Procedure OP-001-003," Reactor Coolant System Drain Down," Revision 18, Change ,

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4 Observations and Findinas The inspectors observed a preevolution briefing conducted by the control room supervisor. The briefing was conducted in a professional manner and roles and responsibilities of the reactor operators performing the evolution were discussed. A dedicated reactor operator was assigned to monitor shutdown cooling system operation and to perform confirmatory calculations of reactor coolant inventory drained from the system. Individual watchstanders performed detailed turnover britfings when breaks I were necessary. The reactor operators performed the evolution in a well-controlled I manner. Communications and peer checking were excellent. The reactor operator l controlling the drain rate closely monitored the diverse reactor coolant level indicators and adjusted drain rate when necessary to ensure that indicated level was consisten The control room super"isor conducted periodic status briefings for the crew to inform them of various plant conditions. However, the inspectors noted that the control room supervisor did not conduct a status briefing in anticipation of completion of steam generator tube draining. Levelindication changes would indicate completion of tube draining or any changes in drain rate that might be appropriate as the reactor loop piping vias being drained. The inspectors noted that Procedure OP-001-003 did not j provide any guidance regarding level indication symptoms expected as the steam '

generator tubes were drained or guidance regarding drain rate as reactor coolant level approached midloo ,

l The inspectors observed that the control room operators anticipated the completion of l tube draining based upon holdup tank level changes and calculation of inventory I drained. Operators communicated well with each other and, when level instruments indicated that the tubes had been drained, the drain rate was reduced from 100 to

,50 gpm and then further reduced as the target levelin the RCS was approached.' Conclusions The control room operators performed the draindown of the RCS in a safe, well-controlled, and effective manne '

l 04.3 RCS Cooldown Rate Exceeded Inspection Scope (71707)

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The inspectors reviewed the Technical Specification (TS) cooldown restrictions and a j graph of the plant cooldown following the manual trip.

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On August 7,1999, the inspectors requested a graph depicting plant cooldown following the reactor trip. During the review, the inspectors noted that some areas of the graph indicated rapid temperature changes during short time intervals. The inspectors

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-5-requested a more detailed graph of the time frames of interest. In supplying this information, licensee personnel discovered that, on August 3, the RCS cooldown rate had been exceede TS 3.4.8.1 states that the maximum cooldown rate for the RCS with cold leg temperatures less than 135*F is limited to 10*F per hour. The cooldown traces on the graphs indicated that, on August 3, the RCS temperature dropped 17"F in approximately 12 minutes and exceeded the TS limit. This drop coincided with tripping RCPs 1 A and 2A. This demonstrates a failure of the operators to anticipate the effect of tripping two RCPs on RCS temperature during plant cooldown. This issue became a Mode 4 restraint until an engineering evaluation was performed to verify that the excess cooldown rate was bounded by the safety analyses. The vendor performed an analysis to determine the allowable heatup and cooldown rates based on allowable reactor vessel stresses. The analysis revealed that reactor vessel integrity had not been compromised by the even The inspectors were concerned that the plant operators did not identify this condition at the time the event took place. Operator awareness of changing plant conditions was lacking in this instanc Exceeding the TS RCS cooldown rate limit is a violation of TS requirements. This Severity Level IV violation is being treated as a noncited violation consistent with Appendix C of the NRC Enforcement policy. Operators did not maintain an adequate awareness of changing plant conditions. This violation is in the licensee's corrective action program as Condition Report 99-0828 (50-382/9916-01). Conclusions A violation was identified for exceeding the maximum TS cooldown rate for the RC The violation had not been identified by the licensee prior to questioning by the inspectors. A subsequent engineering evaluation indicated that the RCS integrity had not been compromised. This Severity Level IV violation is being treated as a noncited violation consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as Condition Report 99-082 O4.4 Plant Startuo Followina Reoairs to RCP 2B Inspection Scoce (71707)

The inspectors observed portions of the plant heatup, reactor startup, and power increase. The inspectors reviewed plant and reactor startup procedures and the estimated ctical boron concentration calculation Observations and Findinas On August 10, the inspectors observed control room activities during the reactor startu The startup was conducted in a very professional manner. Access to the control room

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-6-was enforced. Communication techniques observed were three-way and very thoroug The operations manager was present in the control room during the startup and power increas Conclusions During a reactor and plant startup, the operators conducted these activities in a controlled manner. Management oversight of the control roorn activities was continuously maintaine Miscellaneous Operations issues (92901)

08.1 (Closed) Licensee Event Report (LER) 50-382/97-012-01: Programmatic Breakdown of Overtime Program This LER revision made minor changes to the corrective actions discussed in the original LER. The corrective actions had been fully discussed in closure of Violation (VIO) 50-382/9704-01 in NRC Inspection Report 50-382/98-0 .2 (Closed) VIO 50-382/9716-01: Failure to document basis for operability determinatio The violation was for failure to conduct operability assessments in accordance with the established administrative process. The corrective actions that were taken involved training the operations supervisory staff. The level of detail required in operability assessments was stressed. Also, the administrative procedure was revised to include examples of detail required in operability assessments. The corrective actions were considered to be appropriat II. Maintenance M1 Conduct of Maintenance (61726,62707)

The inspectors observed all or portions of the following maintenance and surveillance activities, as specified by the referenced procedure numbers and maintenance action item numbers:

• 406435 Clean and inspect condenser tubes on Essential Chiller B

• 406221 Inspect dehydrator float valve, chamber, economizer floats, and in-line damper on Essential Chiller B

! * OP-009-002 Emergency Diesel Generator (EDG) A Surveillance

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• OP-903-068 EDG A and Subgroup Relay Operability Verification

• OP-903-123 Control Room Envelope Pressure Test

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In general, the inspectors considered the observed work activities were performed in an acceptable manner. The technicians were knowledgeable and conducted the work appropriately. Some exceptions were noted and are described in Section M4.1 of this repor M4 Maintenance Staff Knowledge and Performance M4.1 Essential Chiller B Condenser Tube Cleanina Insoection Scoce (62707)

The inspectors observed maintenance activities and reviewed associated documentation for cleaning the condenser tubes of Essential Chiller B. These activities were part of a planned maintenance package and worked as schedule ;

) Observations and Findinas i On July 26,1999, the licensee performed maintenance on the condenser of Essential l Chiller B under Maintenance Action Item 406435. The inspectors observed this work l

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and made several conclusions based on these observations. The technicians were in l the process of cleaning the tubes in the condenser after having removed the end covers and baffle plates to gain access to both ends of the tubes. The inspectors reviewed the

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associated documentation for this task and noted that step 3 of the written procedure l stated to remove the condenser covers and step 4 stated to remove the baffle plates.

! Both these steps had sign-offs associated with them, but neither step was signed off as I

completed when they had in fact been completed. The inspectors reviewed the requirements for signing off steps and determined that Procedure W2.101," Procedure Compliance and Usage," Revision 4, step 5.2.2.3, required that completed steps are to be signed off as complete before proceeding to the next step. The inspectors considered this requirement to be clear and unambiguous. The safety significance of this occurrence was minimal; however, the inspectors concluded that this represented a lack of attention to detail and a lack of concern for meeting all the requirements for performing a maintenance task on safety-related equipmen In addition, the documentation for this maintenance task included a checklist to be used during the prejob briefing. The checklist contained items which could be used as an aid to ensure important aspects of the job were discussed during the briefing and then checked off to provide a record of the briefing. The inspectors noted that none of the items were checked off in this checklist. No requirement for the use of this checklist could be located; however, the inspectors considered the nonuse of such a tool to be an additional example of lack of attention to detail and a lack of concern for creating a complete and accurate record of work performed on safety-related equipment. The inspectors noted that a prejob briefing had been conducted for this jo w

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tTwo examples of lack of attention to detail and lack of concern for creating a complete and accurate record of work performed on safety-related equipment were identifie Maintenance technicians failed to sign off procedural steps upon completion of work on ;

the condenser of Essential Chiller B and a checklist to be used during the prejob briefing !

was not utilize M8: Miscellaneous Maintenance issues (92902) - 4 M8.1 - (Closed) VIO 50-382/9715-03: Failure to establish performance criteria for emergency

. lighting syste On July 11,1997, the NRC found that the licensee had failed to establish performance >

goals for the emergency lighting system in accordance with the requirements of 10 CFR 50.65, " Maintenance Rule." .On December 11,1997, the licensee had completed the actions required to place the emergency lighting system in the scope of the Maintenance Rule. All corrective actions have been completed.E Also, refer to

Section F8.1 in this repor !!LEncineerina )

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- E1 Conduct of Engineering (37551) i E1.1" Identified Condition Outside the Licensina Baagig : Insoection Scope (37551)

The inspectors reviewed the licensee's actions regarding a condition that was identified as being outside the licensing basis. The condition concerned the inability of the plant to meet the licensing basis for analyzed rainfall events, Observations and Findinas

- On July 26,1999, the licensee determined that the installed dry cooling tower (DCT)

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i sump pumps were not adequate to protect safety-related equipment in the area from l flooding due to intense rainfalls resulting from the Probable Maximum l Precipitation _(PMP) and the Standard Project Storm (SPS) events. These events are l described in the Updated Final Safety Analysis Report (UFSAR), Section 2.4. !

i The licensee determined that the critical height specified in the UFSAR (1.71 feet) was !

not accurate since some safety-related equipment was located lower than this elevation !

- and would therefore be impacted sooner by a rising water level. In addition, other nonconservatisms were identified. The ponding areas in DCTs A and B and in the fuel handling building were significantly less than specified in the UFSAR. Also, additional roof area was identified, which would contribute to the total amount of rainfall deposited

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9-l l into the DCT and wet cooling tower areas. These nonconservatisms, when taken j together, required an ad6tional 200 gpm pumping capacity to be placed in service within 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> of a PMP event or an additional 100 gpm pumping capacity placed in service within 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> of an SPS event. These capacities were in addition to the assumed installed sump pump capacities for each event.

l The licensee determined, upon discovery of this condition, that both the east and west

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side ultimate heat tinks remained operable even without the additional pumping capacity installed in the DCT sumps. This determination was made based on the availability of two motor-driven installed sump pumps in the west side and one i temporary 100 gpm diesel-driven sump pump on the east side. The diesel-driven pump l was installed during the performance of a modification, which removed the two l

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l motor-driven sump pumps from service. For the east side DCT, weather forecasts were relied upon to confirm the absence of a PMP event in the area. This operability determination was made possible when the licensee determined that single failure criteria did not have to be considered for either a PMP or SPS event. The inspectors j reviewed this determination and considered it to be adequate but weak in that it was not l well supporte l

! The licensee officially reported this condition to the NRC at 12:45 a.m. on July 27. In that report, the licensee stated that it was planned to install high capacity portable diesel-driven sump pumps in each DCT within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The inspectors observed this j work and noted that the diesel-driven sump pump in the east DCT was installed and

satisfactorily tested at 3 p.m. on July 29 (approximately 62 hours7.175926e-4 days <br />0.0172 hours <br />1.025132e-4 weeks <br />2.3591e-5 months <br /> later) and the west side DCT portable sump pump was installed and satisfactorily tested at 1:30 p.m. on !

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August 3 (approximately 180 hours0.00208 days <br />0.05 hours <br />2.97619e-4 weeks <br />6.849e-5 months <br /> later). These times were well beyond the previously j l

established times and reflected an apparent decrease in the urgency of this effort. The I

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temporary diesel fire pumps that were installed were rated at 525 gpm.

l The requirements of 10 CFR Part 50, Appendix B, Criterion lil," Design Control," state !

l that measures shall be established to assure that applicable regulatory requirements !

l and the design basis for those structures, systems, and components to which this appendix applies are correctly translated into specifications, drawings, procedures, and ,

instructions. The requirement goes on to state that deviations from appropriate quality l standards are to be controlled. In this case, the licensee failed to meet these requirements in that the licensing-basis requirements were not appropriately translated into specifications and that deviations from the licensing basis were not controlle The failure to meet the requirements of the licensing basis for two rainfall accumulation

! events with regard to the ultimate heat sink sumps is identified as a violation. This j Severity Level IV violation is being treated as a noncited violation consistent with

Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective l

action program as Condition Report 99-0789 (50-382/9916-02).

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Conclusions j A violation was identified for the failure to meet the requirements of the licensing basis for two rainfall accumulation events with regard to the ultimate heat sink sump Several nonconservatisms were identified by the licensee in the original calculation, which when taken together indicated that additional pumping capacity was required to remove the accumulation of two analyzed rainfall events. The initial operability determination for the ultimate heat sink was considered adequate. The initially stated -

time frame to install additional pumping capacity in the sumps was exceeded due to an J apparent decrease in the urgency of this effort. This Severity Level IV violation is being treated as a noncited violation consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as Condition ]

Report 99-078 E2 Engineering Support of Facilities and Equipment E RCP 2B Seal Failure Inspection Scope (37551)

The inspectors observed engineering suppor1 for the failure of the RCP 2B seal assembly and associated components, which resulted in the forced shutdown of the plant to make repair ]

b. . Observations and Findinas On August 1,1999, the plant was shut down when an indication of a failed seal on RCP 2B was observed by the control room operators. The licensee assembled a Significant Event Response Team to determine the cause of the failure and establish appropriate corrective actions. This was primarily an engineering effort, which gathered all available information and data as it became available. The symptoms of this failure were similar to those seen in several previous events in September 1987, October 1992, June 1995, and July 1996. The cause of the previous events was determined to be failed seal water heat exchanger baffle bolts. A total of six bolts are used to secure the isaffle to the pump shaft. These bolts were found to have been broken in the previous instances, which had resulted in some thread damage and heat exchanger damage. in 1996, the licensee established corrective actions to remedy this condition. These actions included replacing the damaged one-piece baffle, installing new machined bolts made from a higher strength steel, and ensuring proper preload on the bolts by l

measuring the elongation of the installed bolts. The licensee suspected that the cause ;

l of the seal failure on August 1 would turn out to be a similar baffle bolt failur l

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Upon disassembly of the seal and baffle, it was discovered that all six baffle bolts were !

still in place with no apparent damage. Before removing the bolts, the licensee measured the as-found preload on the bolts. The preload was slightly less than the as-left value in 1996 but still within tolerance. The baffle was removed for inspection t

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and it was found to have a significant crack appearing to originate in the inner diameter of the baffle and continuing over the top and down the outer face of the unit. This was identified as the cause of the seal failur The licensee determined that the cause of the crack was most probably fatigue failure, perhaps originating from a preexisting flaw in the baffle. To confirm this, the baffle was decontaminated and sent to a laboratory to undergo destructive testing. In addition, a finite element analysis study was planned. Results from these efforts could provide a definitive root caus Short-term corrective actions included assembling the pump with a new one-piece baffle, installing six new high-strength baffle bolts in the same configuration as was used in 1996, and installing a new seal assembly. The inspectors considered that an acceptable level of confidence was achieved with this action since the failed baffle had been in service for approximately 3 years before failure. The time required for a j fatigue-related failure to reoccur could reasonably be assumed to be greater than the j

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time until the next scheduled refueling outage currently scheduled for the fall of 2000. If a different corrective action is identified based on the results of the studies described above, repairs could be made at that tim The inspectors considered the licensee's actions with regard to the seal and baffle failure to have been good. The Significant Event Response Team was well organized, focused, and provided reasonable recommendations based on sound engineering. No concerns were identifie Conclusions The licensee's efforts to establish the root cause of the seal failure, which forced a plant shutdown, were considered good. A Significant Event Response Team was well -

organized, focused, and provided reasonable recommendations based on sound engineering. A cracked seal water heat exchanger baffle was identified as the cause of the seal failure. The preliminary cause of the crack was identified as fatigue. A new baffle was installed in the same configuration as was used 3 years earlier and additional examinations and modeling were planne E8 Miscellaneous Engineering issues (92903)

E8.1 (Closed) VIO 50-382/01013 (EA 97-099A): Failure to maintain at least one containment fan cooler (CFC) operable per trai On January 29,1997, NRC concluded that the licensee had been in violation of TS 3.6.2.2 related to CFC flow requirements. Four separate violations had been l 'dentified and Special Inspection 50-382/9703 had been conducted. Escalated

} Enforcement Activity (EA)97-099 had been assigned to address issuance of the i violation ,

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e a-12-On June 9,1997, the licensee issued a response to the violations outlining the corrective actions that had been or would be performed to prevent recurrence of the violations. These included: (1) establishing administrative requirements that cJl CFCs be operable; (2) conducting a complete review of TS and UFSAR flow requirements of CFCs; (3) performing a containment pressure peak analysis to demonstrate acceptance criteria had been met; (4) changing the TS to more clearly define CFC flow requirements and acceptance criteria; (5) conducting a component cooling water system flow balance to verify CFC flow rates in support of UFSAR and TS changes; (6) finalizing operating procedures based on CFC and component cooling water flow tests; and (7) training personnel to improve design-basis awareness. All corrective actions related to these violations have been complete E8.2 (Closed) VIO 50-382/01023 (EA 97-0998): Failure to maintain adequate design control for the containment cooling syste The corrective actions associated with this 10 CFR Part 50, Appendix B, Criterion lil, {

violation have been completed as discussed in Section E8.1 of this repor ]

E8.3 (Closed) VIO 50-382/01033 (EA 97-099C): Failure to establish adequate surveillance test procedures for TS Surveillance Requirement 4.6.2.2. The corrective actions associated with this 10 CFR Part 50, Appendix B, Criterion XI, violation have been completed as discussed in Section E8.1 of this repor E8.4 (Closed) VIO 50-382/01043 (EA 97-099D): Failure to implement adequate corrective action tu change CFC design basi The corrective actions associated with this 10 CFR Part 50, Appendix B, Criterion XVI, violation have been completed as discussed in Section E8.1 of this repor E8.5 (Closed) VIO 50-382/9708-05: Failure to maintain design contro This violation cited four examples of failure to appropriately implement 10 CFR Part 50, j Appendix B, Criterion 111. The licensee addressed each of the examples with appropriate corrective actions as summarized belo Example 1 involved a design change that added electrical loads to an EDG without ensuring that the loads had been maintained below the values assumed in the safety analysis. Electrical current measurements were taken on the added equipment. The ,

additional loads were verified to be bounded by the assumptions in the safety analysi The UFSAR was updated to show the additional loads and the associated procedures

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were appropriately revise Example 2 involved failure to account for instrument uncertainty in the containment spray riser levelinstrumentation. The licensee had issued LERs 50 382/97-011 and

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-13-97-011-01, which delineated corrective actions for this issue. These actions have been completed and reviewed as described in the LER closure in inspection Report 50-382/97-2 Example 3 involved addition of air filter material to a core protection calculator cabinet without evaluating the effect on cooling air flow. The filter material was evaluated and air flow through the instrument cabinet was found to be acceptabl Example 4 involved errors in an engineering ground rules document. The errors in the document were corrected. A formal method for reviewing calculations was implemented. The configuration change process has been updated to ensure reviews have been conducted and management expectations have been understoo E8.6 (Closed) Insoection Followuo item (IFI) 50-382/9708-07: Review of licensee evaluation of the adequacy of instrument uncertaintie i l

in response to a 10 CFR 50.54(f) information request in October 1996, the licensee had j committed to evaluate instrument uncertainties associated with TS limiting condition for !

. operations. This followup item was opened to track and review results of this effor l l

The status of this item had been discussed in NRC Inspection Report 50-382/97-25 and left open because the project had been only 80-85 percent complete. On March 31,1999, the project was completed and correspondence from the licensee was sent to NRC as W3F1-99-0053, with results from the review efforts attache The inspectors reviewed the results of the evaluation and found them to be appropriat However, a related issue involving instrument inaccuracies and safety system flow uncerta:nties has been opened as Unresolved item 50-382/9906-04. This issue will be addressed in future inspection IV. Plant Support R1 Radiological Protection and Chemistry Controls R Radioloaical Protection Personnel Activities Insoection ScoDe (71750)

The inspectors reviewed routine and nonroutine activities of radiological protection personne Observations and Findinas During routine tours, the inspectors observed posted radiation survey measurements, which were required by licensee procedures and NRC regulations. A sample of doors was found to be locked as required for the purpose of radiation protection. Licensee personnel working in radiologically controlled areas were observed following applicable procedures for radiation protectio .

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-14 The inspectors toured the containment building during the outage and found the l conditions to be similar to those previously documented. No concerns in this area were l identified. The inspectors observed work in progress to repair the RCP 2B seal and associated components. Radiation protection personnel assigned to this job demonstrated a good level of knowledge concerning the progress of this job. A closed circuit television camera was set up to provide visual monitoring of maintenance personnel while keeping radiological exposure ALARA. In addition, remote dosimetry was utilized to continuously monitor those personnel in the immediate vicinity of the RCP. The inspectors considered these methods to be innovated and effectiv Conclusions Radiological protection personnel demonstrated a good level of knowledge and utilized innovative and effective methods to monitor the reactor coolant pump seal replacement job. The containment building condition was considered adequat S4 Security and Safeguards Staff Knowledge and Performance l

S4.1 Routine Security Performance Observations l l

I Inspection Scope (71750)

The inspectors conducted several observations of routine security activities in the primary access portal (PAP) and areas within the protected area (PA). Observations and Findinas The inspectors conducted three extended observations in the PAP during this inspection period. During these observations, the inspectors considered the general conduct of .

security to be adequate. However, several areas of concern were identified. These I

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included continued use of poor communication techniques. Both radio and face-to-face communication lacked the use of three-way techniques. Several examples of informal communication were noted and included inconsistent communications between the X-ray machine operator and the security officer performing hand searches of articles. It was not clear to the inspectors which articles were designated to be hand searched after passing through the X-ray machine. The technique used to designate such articles varied from officer to officer.

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Written communication was also noted as questionable. The inspectors observed the activities of a security officer posted at the entrance to the control room to enforce the 16-man rule. This rule was placed in effect when carbon dioxide levels reached 0.3 percent in the control room during a modification to replace the broad range gas

monitors. A temporary instruction sheet was at the watch station to specify the duties l and responsibilities of the watchstander. The inspectors noted that this sheet had

[ spaces for signatures for the official preparing and for the person approving the document. Neither signature was present on the document at the watchstation. The inspectors questioned the validity of such a document and requested to see the

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approved original. A copy was located with the preparer's signature, but no copy with

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both the preparer's and approving officials' signatures was produced. The inspectors considered issuing unapproved written communication to the security officers in the plant to demonstrate a lack of accountability for such communicatio On August 6,1999, the inspectors observed a copy of a magazine near a temporary security officer post in the controlled access area. The inspectors considered the presence of this unauthorized reading material to be a potential distraction to security personnel performing monitoring duties in this area of the plant. Two security officers were present at the watchstation when this observation was made. When questioned, the officers indicated that the magazine had just been discovered under a nearby piece of equipment and that the owner was not known. The inspectors concluded that the most probable scenario was that a previous watchstander had brought the unauthorized reading material into the area and failed to remove it at the end of the shift. The licensee performed an investigation and took statements from involved security personnel. No responsible individual was locate Based on the observations described above, the inspectors considered the actions of I the security personnel to be unprofessional and demonstrated a lack of rigor and lapses I in attention to detail. These included informal radio, face-to-face, and written communication techniques and low standards and expectations set during the performance of official duties, l Conclusions The actions of site security personnel were considered unprofessional and demonstrated a lack of rigor and lapses in attention to detail. Several examples of informal radio, face-to-face, and written communication techniques were observed. The presence of unauthorized reading material at a watchstation was an example of lovt standards and expectations for the pnrformance of official dutie S4.2 Employee Entry into the PA Insoection Scope (71750)

The inspectors observed a plant employee attempting to enter the PA through the PAP on July 28,199 Observations and Findinas

! On July 28, the inspectors observed a plant employee attempt to enter the PA through Turnstile 1 in the PAP. During this process, an access denied alarm came into the l central alarm station (CAS). The CAS operator immediately informed the final access I control officer (FASCO) in the PAP of the alarm. The employee was not able to gain access through Turnstile 1 on this attempt. The security officer assigned to monitor the turnstiles was directed to accompany the employee to Turnstile 2 and attempt another entry.

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16-After using the card reader and the hand geometry unit, the employee received an ID-verified message and the turnstile was heard to unlock. The employee attempted to enter through the turnstile but could not because the turnstile was in the exit mode. The turnstile should have been in the entry mode to allow entry into the PA. Upon realizing this, the FASCO placed the turnstile in the entry mode. The CAS operator directed the FASCO to unlock the turnstile and have the turnstile monitoring officer turn the turnstile untilit locked. Upon hearing the turnstile unlock, the employee proceeded to enter the PA before the turnstile monitoring officer had a chance to manually turn the turnstil The employee was directed to stop in an area just inside the PA. The CAS operator noted that the employee was stilllogged out of the PA even though he was physically inside the PA. The turnstile monitoring officer was directed to enter the PA to ensure the employee stayed in the area until this situation was corrected. The CAS operator manually logged the employee into the PA after verifying his badge information, and the employee was allowed to procee Following this event. the inspectors questioned the FASCO as to the details of what had just occurred. The officer seemed confused and unsure. The inspectors contacted security supervision to inform them of this event and to request clarification on the details. Security supervision obtained written statements from the FASCO and CAS officer and provided these to the inspector Upon reviewing this event, the inspectors made several conclusions. The situation appeared confused and not well controlled. The officers involved did not communicate effectively, which contributed to the level of confusion. Also, the on-scene officers failed to take positive control of the situation when the employee was allowed to enter the PA prior to being properly logged in. The FASCO demonstrated a lack of attention to detail when he failed to ensure that the turnstile was in the proper mode to allow access to the P Conclusions Security officers involved in an event in which a plant employee had difficulty accessing the PA were confused and demonstrated a lack of attention to details. Ineffective communication techniques contributed to the level of confusion and on-scene security officers failed to take positive control of the situation. Security officers failed to ensure that the turnstile was in the proper mode of operation to allow access to the protected are F8 Miscellaneous Fire Protection issues (92904)

F8.1 (Closed) VIO 60-382/9715-06: Failure to provide required emergency lighting unit On August 4,1997, the inspectors found that emergency lighting had not been installed in accordance with 10 CFR Part 50, Appendix R. The licensee performed a walkdown and found several additional areas that required emergency lighting.

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-17-Based on the violation and additional walkdowns performed by the licensee, emergency lighting units were installed in several areas throughout the plant. The emergency lighting units comply with 10 CFR Part 50, Appendix R,8-hour criteria. All corrective actions have been complete V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management on August 19,1999. The licensee acknowledged the findings presente The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie ,

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ATTACHMENT SUPPLEMENTAL INFORMATION PARTIAL LIST OF PERSONS CONTACTED Licensee R. F. Burski, Director Site Support C. M. Dugger, Vice-President, Operations E. C. Ewing, Director, Nuclear Safety & Regulatory Affairs C. Fugate, Operations Superintendent A. Harris, Acting Superintendent, System Engineering J. G. Hoffpauir, Manager, Operations T. R. Leonard, General Manager, Plant Operations D. C. Matheny, Refuel 9 Coordinator E. Perkins, Jr., Manager, I bensing G. D. Pierce, Director of Quality B. Thigpen, Director, Planning and Scheduling A. J. Wrape, Director, Design Engineering INSPECTION PR'OCEDURES USED

- 37551 Onsite Engineering 61726 Surveillance Observations 62707 Maintenance Observations 71707 Plant Operations 71750 Plant Support Activities 92700 Onsite LER Review  !

! 92901 Followup-Plant Operations 92902 Followup-Maintenance l 92903 Followup-Engineering 93702 Prompt Onsite Response to Events l

ITEMS OPENED. CLOSED. AND DISCUSSED Opened 50-382/9916-01 NCV Exceeded the maximum TS RCS cooldown rate limit (Section 04.3).

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v-2-50-382/9916-02 NCV Failure to meet the requirements of the licensing basis for two rainfall accumulation events with regard to the ultimate heat sink sumps (Section E1.1).

Closed 50-382/9916-01 NCV Exceeded the maximum TS RCS cooldown rate limit I (Section 04.3).

50-382/97-012-01 LER Programmatic Breakdown of Overtime Program (Section 08.1).

50-382/9716-01 VIO Failure to document basis for operability determination (Section 08.2).

50-382/9715-03 VIO Failure to establish performance criteria for emergency lighting system (Section M8.1).

50-382/9916-02 NCV Failure to meet the requirements of the licensing basis for two rainfall accumulation events with regard to the ultimate heat sink sumps (Section E1.1).

50-382/01013 VIO Failure to maintain at least one containment fan cooler (CFC)

(EA 97 099A) operable per train (Section E8.1).

50-382/01023 VIO Failure to maintain adequate design control for the (EA 97-0998) containment cooling system (Section E8.2).

50-382/01033 VIO Failure to establish adequate surveillance test procedures for (EA 97-099C) TS Surveillance Requirement 4.6.2.2.B.2 (Section E8.3).

50-382/01043 VIO Failure to implement adequate corrective action to change (EA 97-099D) CFC design basis (Section E8.4).

50-382/9708-05 VIO Failure to maintain design control (Section E8.5).

50-382/9708-07 IFl Review of licensee evaluation of the adequacy of instrument uncertainties (Section E8.6).

50-382/9715-06 VIO Failure to provide required emergency lighting units (Section F8.1).

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l' -3-LIST OF ACRONYMS USED ALARA as low as reasonably achievable CAS central alarm station  !

CFC containment fan cooler l

CFR Code of Federal Regulations

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DCT dry cooling tower l EA enforcement activity EDG emergency diesel generator l FASCO final access control officer l

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IFl inspection followup item LER licensee event report NCV noncited violation NRC Nuclear Regulatory Commission PA protected area PAP primary access portal PDR Public Document Room PMP probable maximum precipitation RCP reactor coolant pump RCS reactor coolant system SPS standard project storm TS Technical Specification UFSAR Updated Final Safety Analysis Report VIO violation l

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