IR 05000395/1997013
| ML20198N695 | |
| Person / Time | |
|---|---|
| Site: | Summer  |
| Issue date: | 12/23/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20198N674 | List: |
| References | |
| 50-395-97-13, NUDOCS 9801210176 | |
| Download: ML20198N695 (46) | |
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LU;S;NUCLEARREGULATORYCOMMISSION
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REGION II'
-Dockit-No.: .~ 50-395 :
License No.:- NPF-12-
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Report No.:- 50-395/97-13L-Licensee: South Carolina Electric & Gas (SCE&G)
Facility:. . V. Ci Summer Nuclear Station
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L Location:' P 0. Box-88 Jenkinsville, SCL29065 Dctes: October 19 - November 29, 1997
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Inspectors: B. Bonser Senior Resident Inspector T. Farnholtz. Resident Inspector W. Holland. Reactor Inspector. RII (Section E8.1)- .
D. Jones, Reactor Inspector RII (Section R1.2). i g" J. Blake, Reactor Inspector, RII-(Section M2.4, M2.5, M and M8.3)-
W Stansberry. Safeguards Inspector. RII (Section S1.2, S2.1, S2.2 S2.3. 52.4,153.1, S3.2 and SS.2)
-Approved by:- R. C. Haag, Chief, Reactor _ Projects Branch 5 ,
Division of Reactor Projects j i
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EXECUTIVE SUMMARY V. C. Summer Nuclear Station NRC Inspection Report No. 50-395/97-13 This integrated inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a six-week period of resident ins)ection; in addition, it includes the results of announced inspections ay regional inspectors.
Doerations
- Reactor core rel i d activities and low power physics testing were conducted with good control and communication between reactor engineering and operations personnel (Section 01.2).
e The reactor startup following the refueling outage was conducted safel The approach to criticality was controlled and deliberate (Section 01.3).
. A containment inspection was conducted prior to entry into Mode 4. The inspectors observed no loose debris in the containment which could be transported to the residual heat removal and containment spray recirculation sumps and cause restriction of the pump suctions during loss of coolant accident conditions (Section 02.1).
. Control room operators were relying on a cold calibrated pressurizer level instrument with a Work Request (WR) tag attached which indicated that the meter was not accurate. The operators failed to question the reason for the tag on the instrument which, at the time, was the primary Reactor Coolant System (RCS) level indication. The work to correct the meter reading had been completed earlier but the tag had not been removed (Section 04.1).
- A review of the licensee's actions to obtain a Notice of Enforcement Discretion for the A Diesel Generator (DG) concluded that the licensee was not adequately are)ared to respond to questions on information that was necessary for t1e 4RC to make a well considered decision in granting discretion to the licensee (Section 06.1).
- A review of the licensee's overtime policy during the refueling outage concluded that the policy adhered to the administrative controls in Technical Specifications (TS) and station administrative procedures for extended periods of shutdown for refueling (Section 06.2).
- The Plant Safety Review Committee reviews were thorough and
. comprehensive, and focussed on safety. The inspectors concluded that all relevant issues that could affect plant restart or power escalation were adequately reviewed (Section 07.1).
. - An observed Nuclear Safety Review Committee meeting met TS requirements and provided constructive review and feedback to plant management (Section 07.2).
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.~ -A' review of.the V- C. Summer Institute for Nuclear Power Operations .
1(INPO) report concluded that-the~ content of the report was consistent with- recent NRC assessments: of. licensee' performanc '
- Maintenance
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. A- All observed maintenance ta'+.s on the B DG were conducted-in a competent $
and. professional manner. Appropriate, tools, equipment and procedures ,
were used.(Section M1.1).
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- Three of.five recent Centrifugal Charging Pump (CCP)~ seal failures were l-attributed to ina>propriate maintenance activities. The applicable procedure andLtec1nical manual did not contain sufficient detail to successfully replace the seals (Section M1.2)'. ,
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.- The maintenance task to set the upper internals into the' reactor vessel was performed in a professional and deliberate manner. The pre-job briefing for this task was detailed and thorough (Section M1.3).
- The maintenance performed to re) air a head gasket leak on the: letdown heat exchanger was adequate. T1e use of a new style gasket and an-increase-in bolting torque resulted in a successful repair (Section-
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a M1.4).
. -A review of the completed plant modification to restore wide range Reactor Coolant System loop B hot leg-temcerature indication at the control room evacuition panel concluded that the instrument was operable-
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e The licensee identified and repaired the A DG on two occasions when it was found to be inoperable during routine surveillance testing. An-inspector followup item was opened to followup on the licensee's efforts
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to identify the root cause and corrective action for the-A DG problems
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. Nine surveillance tests were performed satisfactorily and in accordance with approved )rocedures. . Personnel conducting the tests demonstrated a good level of (nowledge (Section M2.1).
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-e ' Deficiencies in the method used to document snubber test results was
. Identified in a OA-generated CER.. The licensee made-no changes in their -
' testing process as a result of this CER. A URI was-identified pending
- further review of the licensee'- administrative process for testing new "
isnubber to determine if appropriate action was taken. (Section M2.2- ).
el L A'non-cit'ed violation was' identified for-failure to meet an eight hour 1TS' requirement to demonstrate the operability of.AC offsite sources with a !a DG inoperable (Section M2.3).'
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= 1 TThe/ISI program was well organized. and on-track to complete the
- required inspections during the current.40-month inspection period y 1(Section M2.4);
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- e: The licensee continued to conduct a conservative eddy-current inspection _ -
program on recently replaced steam generators (Section-M2.5).
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e The licensee's' flow accelerated corrosion program is a mature program that has been doing a good job of finding and replacing affected pipirt components (Section M2.6).
- A non-cited. violation was identified for the failure to' conduct required surveillance _ testing on the C charging /high head safety injection pum The pump vibration was in the alert range during full flow testing conducted during Refueling Outage-8. The licensee faC a to recogniz that this-required doubling the-normal 18 month test frequenc (Section M8.2),
c . The combination of two unrelated snubber failure problems in one event report. LER 97-004. showed a lack of-sensitivity to the issues being discussed. This combination of the two problems tended to minimize the .
.importance of both problems (Section M8.C). !
. A violation was-identified for failure-to conduct technic specification required snubber inspections this raulted in failed snubbers being undetected for an additional 18 month (Section M8.3).
Enaineerina e Based on a-review of a fuel performance assessment the inspectors concluded that-there was no immediate concern with the current cycle 11 fuel meeting the reload safety analysir (Section El.1),
e An engineering evaluation to-determine the cause of five CCP seal failures was complete and detailed and included all relevant fact Reasonable conclusions were made based on these facts (Section E2.1).
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e The licensee's threshold for formal identification of problems for the auxiliary building leak detection system in their corrective action-program was judged to be a weakness (Section E8.1).
Plant Suocort
. The~ licensee was properly monitoring and controlling personnel radiation exposure and posting area radiological conditions in accordance with 10 CFR Part 2 Housekeeping dn the Radiation Control Area (RCA) was-
-very good during the refueling outage. Unexpected results from shutdown chemistry ~ controls resulted in elevated dose rates from the RCS and
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outage asilow as reasonably achievable goals being exceeded (Section R1.2).
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He: A violation was identified for the failure to follow posted health physics' requirements. An individual was. observed using a chewing
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' tobacco product in the RCA--(Section R4.1).
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- *: , served security activities including compensatory measures were found; !
ito be acceptable during.the increased refueling ~ outage activity _(Section -
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.. -The: licensee used compensatory measures 1that ensured thefreliability of !
security related equipment and devices. This evaluation verified that the licensee employed compensatory measures when security equipment t .
failed or its performance was impaired (Section-S1.2).
- 1 The evaluation of-the protected area access controls for. packages and I personnel revealed that.the criteria of:the- Physical-Security Plan (PSP)
were being followed. (Section S2.1), .
.- LThe-licensee was complying with the criteria in the PSP and Security Plan Procedures for alarm stations and communication equipment'
(Section S2.2).
- - The licensee's intrusion detection systems and-assessment aids were functional, well maintained, effective for both covert and overt penetration attempts. and met licensee commitments (Section S2,3).
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e' The-licensee used programs that will ensure the reliability of security related equipment and devices.- The testing and maintenance program was a strength in the security program (Section S2.4).
.- Changes to the PSP and the Training and Qualification Plan did-not decrease their effectiveness (Section S3.1).
. -Safeguards events were being appropriately analyzed, tracked, resolve .
-and documented (Section S3.2)
-. The security force was being trained according to the Training and Qualification Plan and regulatory requirements (Section S5.2).
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Report Details Summary of Plant Status ~-
The Unit began this inspection period shutdown and in a refueling' outage. On November 5. a dilution to criticality was commenced and the plant entered Mode-2. . Mode 1 was entered on November 7 and power was-incrcased to 100 percent by November 14.- The inspection period. plant remained at full power for the remainder of the
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I. Ooerations l 01 -Conduct of Operations 01.1 General Comnents (71707)
Usingilnspection. Procedure 71707. the' inspectors conducted frequent reviewt of ongoing plant operations. In general, the conduct of-operations was professional and safety-conscious: specific events and -
noteworthy observations are detailed in the sections belo .2 Plant Ooerations Durina Retuelina Outaae 10 (RF-10) .
' Insoection'Scoce (71707)
The inspectors observed refueling and low power physics testin L Observations and Findinas The inspectors observed reactor core reloading operations which were-performed in accordance with Reactor Engineering Procedure
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(REP)-107.013. " Core Reload." Revision-1. Control of the process was maintained by reactor engineering personnel in the. main control room who were in continuous communication with personnel in the fuel handling building and in the reactor building. The inspectors observed good communication-techniques and positive control of each fuel assembly from
.the spent fuel pool to the assigned' location in the reactor vessel. No
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problems or concerns were identifie The-inspectors observed portions of reactor core physics testing that was-performed at power levels less than 5 percent. The purpose of these tests was to measure the fundamental nuclear characteristics of th ~
reactor core and related instrumentation. The provisions of Technical
~ Specification -(TS) 3/4.10. "Special Test Exce)tions." were used to-
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perform the required tests. The. inspectors caserved good coordination and communication between reactor _ engineering personnel and operations
. personnel during the performance of the testing. The results were
'within the acceptance: criteria'of each test with no unusual or :
unexpected' data obtained.-
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c. Conclusions Reactor core reload activities and low power physics testing were conducted with good control and communication between reactor -
engineering and operations personne .3 Reactor Startuo Observatiqrls a. 1030ection Scone (71707)
The inspectors observed initial reactor startup following the refueling outag b. Observations and Findinos On the evening of November 5. the inspectors observed initial reactor criticality evolutions following completion of the refueling outag The reactor was diluted to criticality using reactor engineering 3rocedure. REP-107.003, "Beginning of Cycle Dilution To Criticality,"
levision 7. At 8:45 p.m. with control rods withdrawn a controlled dilution was commenced from about 2329 ppm boron in the Reactor Coolant System (RCS). At 11:51 p.m. the reactor was declared critical by the reactor operator. The estimated critical boron concentration was 1917 pp Actual critical boron concentration was 1965 ppm which was well within the specified acceptance range. The ins)ectors observed good command and control throughout the dilution. T1e control room supervisor, reactor operator and the reactor engir.eers present closely monitored reactivity changes and changed dilution rates based upon the Inverse Count Rate Ratio (ICRR) plot. The inspectors observed that the approach to criticality was controlled and deliberate, c. Conclusions The reactor startup following the refueling outage was conducted sefel The approach to criticality was controlled and deliberat Operational Status of Facilities and Equipment
- 02.1 Containment Insoection Insoection Scooe (71707)
The inspectors performed a containment walkdown prior to the plant entering Mode 4 to check the material condition of the containment and to specifically check the Residual Heat Removal (RHR) system and Containment Spray (CS) system recirculation sumps for foreign material.
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b. Observations and Findinas On November 1, the inspectors accompanied by the Outage Manager and a Health Physics (HP) technician performed a containment inspection prior to the licensee's final containment closecut inspection. The inspectors visually inspected containment housekeeping, component and instrument conditions, storage of equipment and material, pipe hangers, snubbers, restraints, and the reactor cavity. The inspectors also performed a visual inspection of the RHR and CS sump area. Overall condition of the containment was found to be satisfactory. The containment sumps were found to be clean. The inspectors identified one concern. Adjacent to the sumps, work on a reactor compartment cooling fan. XFN-9. was observed to be in progress. In order to control foreign material a sheet of plastic had been placed over the sump grating. During the walkdown the inspectors identified several questions. The licensee responded to all questions promptly after the inspection. There were no other concerns identifie On November 2, the inspectors accompanied Operations personnel on the final closecut inspection of the containment prior to establishing containment integrity. The inspectors observed operators removing the protective plastic sheeting covering the sump and taking it out of containment. The inspectors concluded from this containment inspection that there was no loose debris present in the containment which could be transported to the RHR and CS recirculation sumps and cause restriction of the pump suctions during Loss of Coolant Accident (LOCA) conditions, c. Conclusions A containmult inspection was conducted prior to entry into Mode There was no loose debris present in the containment which could be transported to the RHR and CS recirculation sumps and cause restriction of the pump suctions during LOCA conditions.
04 Operator Knowledge and Performance 04.1 Main Control Board Observations Durino Mode 5 a. Insoection Scoce (71707)
The inspectors made frecuent control room observations and performed main control board walkcowns during plant tours, b. Observations and Findinas On October 29, with the plant in Mode 5. Cold Shutdown, the inspectors conducted a control room tour and a main control board walkdown. The procedureinuseatthistimewasGeneralOperatingProcedure(GOP)-1 Recovery From Refueling and Return to Cold Shutdown (Mode 6 to Mode 5)." Revision 9. Preparations were being made to perform integrated safeguards testing with pressurizer level being maintained at approximately 25 percent as indicated on the cold calibrated pressurizer
level instrument (LI-462) on the main control board. The inspectors noted a Work Request (WR) tag attached to the cold calibrated pressurizer level instrument. The control room operators were not aware of the reason for the tag when questioned by the inspector The WR tag indicated that the instrument had trended high on the RCS draindown. The WR document a sociated with the tag (No. 9717658) was originated on October 8. The cause of the erroneous indication was determined to be a reference leg for level instrument LI-462 that was slightly low. The reference leg was refilled and the reading was verified to be satisfactory. This work was performed on October 1 The post reviews for this work request were completed on October 2 The WR tag should have been removed at that tim At the time of this observation. the primary R.CS level instrument being used by the operators was the cold calibrated pressurizer level mete The inspectors were concerned that the operators sere relying on this instrument with a WR tag on it that indicated that the meter was not accurate. Also, the operators were not aware of the reason for the ta The inspectors concluded that this indicated a lack of a qJestioning attitude on the part of the control room operators. The safety significance of this observation was mimmal since the meter had been repaired and was verified to be reading satisfactorily after the repai c. Conclusions Control room operators were relying on a cold calibrated aressurizer level instrument with a WR tag attached which indicated t1at the meter was not accurate. The operators failed to question the reason for the tag on the instrument which, at the tin'e. was the primary RCS level indication. The work to correct the meter reading had been completed earlier but the tag had not been removed.
06 Operations Organization and Administration 06.1 Notice of Enforcement Discretion (N0ED)
a. Insoection Scone (71707)
On the evening of November 13. the licensee requested and obtained a NOED from the NRC. The NRC granted the licensee discretion to not enforce compliance with the 72-hour Action statement of TS 3.8.1.1. "A.C. Sources." for twelve hours beyond the expiration time. The inspectors reviewed the licensee's actions to obtain the N0E b. Observations and Findinos As a result of load oscillations experienced on the A Diesel Generator (DG). while performing a routine monthly surveillance test on November 11. the licensee declared the A DG inoperable at 4:00 a.m. (see Section M1.6). The licensee recognized that the maintenance and testing
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necessary to declare the DG operable could exceed the 72-hour Action
' statemen In requesting the N0ED the licensee followed the guidance
. contained in NRC Administrative Letter 95-05 " Revisions To Staff Guidance For Implementing NRC Policy On Notices Of Enforcement
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Discretion."
The licensee contacted the NRC Region II office and requested Enforcement Discretion'to complete repair and retest of the A train D The licensee requested a twelve hour extension of the 72-hour Action
' Statement in Technical Specification 3.8.-l.1.b.4. "A.C. Sources." The <
licensee stated that the remaining work and testing. required to declare the A-DG operable would likely exceed the remaining LCO Action time that would-expire at 4:00 a.m. on November 1 At about 4:40 p.m. on November 13. a telephone conference call wa s conducted between the licensee, and NRC Region II and headquarters
. staff. The licensee explained the technical problem with the A DG.and-their efforts to return it to service. The licensee then outlined the twelve areas contained in the Administrative-Letter. These areas covered the information to be included in the request for enforcement discretion. During the telephone conference, the NRC staff questioned the licensee on the plant's current o)erational status and any compensatory actions that would be tacen. It appeared to the NRC staff that the licenseedtici ants in the telephone call had not adequately prepared for nor tiorough y considered the items to be discussed. The licensee was not complete y aware of equipment that was currently Out-Of-service (00S) or equipment that was scheduled for maintenance or testing. Also, the licensee had not planned for implementing any compensatory actions-for the A DG being 00S for greater than 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Of particular concern to the NRC was that the conference call did not include licensee personnel with an o]erations perspective or senior licensee management who should have >een able to discuss these item ,
During a-subsequent conference cali between the NRC staff and the plant
' manager additional information regarding the status of plant equipment and compensatory measures that the licensee planned to implement were discussed. After a thorough review of the facts, at 6:45 p.m. on Novemt,er 13 the NRC Region II office--verbally granted enforcement discretion to the licensee for a )eriod of twelve hours beginning at 4:00 a.m. on November 14. The A Xi maintenance and testing was completed and the DG was returned to service at midnight on November 13.'
1997. Sincezthe A DG was returned to service within the 72-hour Action Statement of TS 3.8.1.1.b.4. the actual 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> NOED extension was not needed for the A DG repair; activit After the A DG was returned to service. the inspectors reviewed the overall repair effort and concluded that the time estimated to com)lete the A DG testing, as stated by the licensee when requesting the N0E did not accurately characterize the actual scope of testing. During the conference call the licensee stated that four separate tests would be
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required with a total duration of approximately nine hours plus time
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required to rewrite one of the test procedures. Only two separate tests
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were performed due-to; combining the testing-requirement of three-tests-into onetintegrated test. The actual time to complete the testing;was; about five and a half hours. The-inspectors concluded that licensee
, individuals on the conference call lacked specific knowledge of the A DG -
retest requirements, which resulted in' inaccurate testing estimate Conclusions A review of the licensees actions to obtain a N0ED for the A DG concluded that.the licensee was not-adequately-prepared to-respond to-questions on information that was necessary1for the NRC to make a well _ ,
considered decision in granting discretion to the-license .2 ~Refuelino Outaae Workina Hours Ja; Jnsoection-Scooe-(71707)
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The inspectors reviewed the licensee's overtime policy for the refueling-outag l
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b .- Observations and Findinas During the outage the licensee authorized a majority of the plant staff to work a 12-hour day seven day'a week-schedule. The inspectors-observed that the Operations staff continued to work a 12-hour day schedule. One shift of Operations staff was normally responsible for plant operations for four-shifts and then would be assigned to
' administrative tasks or take days off for the' remaining three day This policy was-ap3 roved by the General Manager fcr Nuclear Plant >
0)erations at the )eginning of the outage. The inspectors concluded t1at the licensee's overtime policy durin-totheAdministrativeControlsinTS6.2.gtherefuelingoutageadhered-2.e and Station Administrative
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Procedure (SAP)-152 " Control Of Overtime For Station Personnel."
Revision 7. for_ extended periods of shutdown for refuelin , Conclusions A review of the licensee's overtime policy during the refueling outage i concluded that the policy adhered to the administrative ~ controls in TS and station administrative procedures for extended periods of shutdown
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for' refuelin _Quality Assurance in Operations
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- 07.1- P16nt Safety' Review Committee'-(PSRC) Meetinas Insoection Scoce'(71707)
- The inspectors observed-the conduct of PSRC meetings on October 3 .
- November 4.' and November'10. All of the PSRC meetings were related to 1
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plant restart and escalation'to full power following the refueling 3 outag {
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< : Prior to entering Mode 4. Hot Shutdown, and Mode 2. Startup, and during-
x power escalation the PSRC conducted a comprehensive readiness review to .
. ensure the plantLwas prepared for entry into the next phase of plant'.
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restart following the refueling outag ,
Conclusions
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The PSRC reviews were thorough and comprehensive -and focussed on-- '
safety. The inspectors concluded that-all-relevant issues that could affect plant restart-or power escalation were adequately reviewe .2 Nuclear Safety Review Comittee (NSRC) Meetina
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- Insoection Scooe (71707)
The inspectors attended a portion oa NSRC meeting on November 19 to a observe and assess NSRC function , Observations and Findinas An NSRC meeting was held on-November 19 at the licensee's Nuclear
~ Training Center. The inspectors: attended a portion of the day long
- meeting to assess'the activities of the committee. The inspectors
- observed the NSRC review snubber testing results and lessons learned.
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the status of charging pump-issues, and main condenser cleaning issue >
i The inspectors observed that the required number of NSRC members were present and that the committee was providing an independent review ofL '
the activities designated in the TS. The inspectors concluded that the
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NSRC meeting was providing constructive review and feedback to plant-management. _
L Conclusions An observed NSRC meeting met TS requirements and provided constructive
' review and feedback-to plant management.
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08: - Miscellaneous' 0perations Issues 08.1= Review of Institute For Nuclear Power Ooerations'(INPO) Recort -
ca.' Insoection Scoce-(71707)
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The inspectors reviewed the interim INP0 evaluation report for
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VEC., Summer, bh Observations-and Findinos
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The:INP0 onsite evaluation was conducted during the weeks of June 23 and
'30,c1997. The inspectors reviewed the INP0: report:to identify any
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issues that were not consistent with NRC findings and assessments The issues ident9"ed in the INPO report were found to be consistent ath recent NRC assessments of licensee performanc c. Conclusions A review of the V. C. Summer INP0 report concluded that the content of the re,' ort was consistent with recent NRC assessments of licensee performanc II. Maintenance M1 Conduct of Maintenance M1.1 Diesel Generator Maintenance Insoection Scone (62707)
The inspectors observed all or portions of the following Nork activities:
- Preventive Maintenance Task Sheet (PMTS) P0205007. Disassembl Inspect, and Clean Lube Oil Cooler Thermostatic Temperature Control Valve for the B Diesel Generator (DG).
- PMTS P0205009. Disassemble. Inspect, and Clean Jacket Water Cooler Thermostatic Temperature Control Valve for the B D e PMTS 9715369. B DG Service Water (SW) Heat Exchanger Performance -
Intercooler and Injector Cooling Water Heat Exchange b. Observations and Findinos The observed maintenance activities on the B DG were conducted in a professional and campetent manner using appropriate procedures. All of the observed work was performed with the work packages present and in
. c. ConclusiQHS All observed maintenance tasks on the B DG were conducted in a compatent and professional manner. Appropriate tools, equipment, and procedui 's were used.
M1.2 Q)3raina Pumo Seal Reolacements Insoection Scooe (62707)
The inspectors reviewed the licensee's activities associated with multiple Centrifugal Charging Pump (CCP) pump seel replacements performed in recent months. A total of four seats were replaced during the period from August 21 through November 7.139 ., ___ _ _ _ _._. . _ _ . _ . . _ . . . _ __
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- b~. l Observations and Findinas' !
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-The1following is :a chronology of eventsEconcerning the CCPLsealf )
failures: ;
e - August 20 - A'CCP outboard seal develo>ed a leak. The seal was- ~
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" - replaced on- August 21. - The cause of tie seal.. failure-was r
indeterminate.
l ?e August 25 - A CCP inboard seal developed a: leak. The licensee -i elected-not.to-replace the seal due to the small- amount of leakage 1 and their plans to continue to monitor the seal leakage.-. The- ,
maintenance activity associated with the. outboard: seal-replacement ;
was identified as a contributor to the inboard seal failur * September 11-- B CCP inboard seal developed a leak. -The seal was replaced on September 16. The cause of the seal failure was ,
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indeterminat r i- 'e- - October 25'- C CCP outboard seal develo>ed a lea The seal was replaced on October 27. The cause of t1e se61 failure was ;
e attributed to age and-inappropriate maintenance activity l f associated with work performed on the outboard end of the pump to address a high-vibration conditio * November 1 - C CCP outboard seal developed a second leak. The seal was replaced for the second ti m on November 7.~ The cause of the seal failure was identified as proper installation when it
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was originally replaced on October 27.
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The magnitude of the seal leakage in each case was minor and did not
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require the associated CCP to be considered ino)erable. -In addition ,
when maintenance was performed on a CCP. the otler two CCPs were available.when required to satisfy TS requirements. However. the
. inspectors were concerned about the high number of seal failures attributed-to inappropriate maintenance activities (three of the'five).
The licensee reviewed the seal. failures with assistance from the seal
- and' pump vendors and identified that the seal replacement section of Mechanical Maintenance Procedure (MMP)-320.012, " Charging / Safety Injection' Pump Ove r aul and Preventive Maintenance." Revision 10.'was' -
- not sufficiently owailed to ensure replacement seals would not leak'.
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These.are precision seal assemblies but the procedure contained-only 10 ,
steps to describe the disassembly process and 12 steps for reassembl In addition.~the CCP technical manual-(IMS-94B-025) did not-contain the level _of detail;necessary to perform this maintenance.
At the end of the inspection period the licensee was in the process of.
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- -revising HMP-320.012 to incorporate the-additional information supplied
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by the' pump and seal company vendor representative _
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c. : Conclusions Three of five recent CCP seal failures were attributed to inaopropriate ;
maintenance activities. The applicable procedure and technic'la manual:
did not contain sufficient detail to successfully. replace the-seal j
- M1,3,' Reactor Vessel Vooer Internals Installation Insoection Scooe (62707).
-The inspectors attended the pre-job briefing and observed the .
installation of the reactor vessel upper internals assembly. The procedure controlling this activity was MMP-500.006. " Reactor Vessel Internals Removal and Installation " Revision b,- Observations and Findinos The inspectors considered the pre-job briefing to be thorough and conducted in a professional manner, All involved parties were present and actively participated. The emphasis was placed on personnel and nuclear safety' concerns and the importance of following the procedur Specific assignments. As Low As Reasonably Achievable (ALARA) concerns, and industry experience were also discussed. It was made clear that-there were no time constraints:or pressures associated with this activit The inspectors observed the setting of the upper internals in the reactor vessel. The personnel conducting this activity were deliberate and careful, No concerns were identified.
<
c. ' .Cspelusions The maintenance task to set the upper internals into the reactor vessel was performed in a professional and deliberate manner. The pre-job
-
briefing for this task was detailed and thorough.
~
M1',4 letdown Heat Exchanaer Reoair Insoection Scoce (62707)
~
The inspectors reviewed the repair of a head gasket-leak on the' letdown heat exchange 'b; Observations-and Findinas-
- 'During the refueling outage, the licensee repaired a head gasket leak on the letdown heat exchanger. The heat exchanger head and gasket were removed and a new style gasket installed. In addition, the studs were replaced. beveled washers were installed, and the torque was increased t ; from:205 FT-LB to 360 FT-LB. The repair appeared to be effective with no observable leakage at-normal temperature and pressure.
.
. , , . - ,.
.. .
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The cause of the leakage was attributed to only a partial crush of the original gasket. -The partial crush of the gasket was due to either inadequate thickness of the gasket or the light stud torque used during the original installation. The licensee measured the thickness of the old style gaskets in the warehouse and found them to be correct. The increase in the stud torque value was done with concurrence from the gasket and the heat exchanger manufacturers and was well within the maximum allowed torque for these studs. The inspectors considered the work associated with repair of the letdown heat exchanger to have been adequat Conclusions The maintenance performed to re) air a head gasket leak on the letdown heat exchanger was adequate. T1e use of a new style gasket and an increase in bolting torque resulted in a successful repai M1.5 Failure of Reactor Coolant System Wide Ranae Temoerature Indication Insoection Scone (62707)
The inspectors reviewed the licensee's actions to restore RCS loo) B wide range temperature indication on the Control Room Evacuation )anel (CREP). Observations and Findinos On November 15 at 10:30 p.m.. the Resistance Temperature Detector (RTD)
providing RCS loop B hot leg Wide Range (WR) Temperature Indication (ITI00423A) on the A train CREP failed high. This placed the plant in the seven-day Action statement for TS 3.3.3.5. " Remote Shutdown Instrumentation." The licensee determined that it was not practical to replace the RTD at power due to temperature and radiation concern There also was t.o spare element directly routed to the CREP that could provide the RCS loop B hot leg WR temperature indication. As an interia signal source the licensee identified a spare RTD element on a RCS loop B hot leg RT The licensee prepared a modification to use the signal from the spare RTD and route it to the CREP. The inspectors walked down the completed modificativ from the spare RTD input in the relay room cabinet to the CREP. The inspectors also reviewed the surveillance test results that
"erified the instrument was within tolerance. The inspectors were
_atisfied that the modification had been installed in accordance with the modification Jackage and the RCS hot leg temperature indication was restored to opera)ility. The WR hot leg instrument was returned to
. service on November 2 c. Conclusions A review of the completed plant modification to restore WR RCS loop B hot leg temperature indication at the CREP concluded that the instrumerit was operabl M1.6 Diesel Generator Inocerability a. Insoection Scoce (62707)
On November 11 and on November 21, the A-DG failed routine surveillance tests by exhibiting load swings while loaded and tied to the 115 kV bu The inspectors reviewed the events and the licensee's actions to restore the A DG to operabilit b. Observations and Findinas On November 11 at 4:00 a.m.. the A DG was declared inoperable after load oscillations occurred during performance of the monthly surveillance test. The DG was operating at its nominal full load rating (4250 kw)
when load oscillations of about 400 to 500 kw above and below the nominal loading occurred. Based on plant and industry experience, and troubleshooting by the licensee it was determined that the oscillations were probably due to a malfunction in either the electronic control unit (EGA) or the hydraulic actuator (EGB) of the Woodward governor. The l'censee was unable to isolate the problem to the EGA or EGB and decided to replace both units. Re)lacement and set-up of the governor continued through day shift on Novem)er 13. After removing the EGA. the licensee bench tested the unit and found that the EGA was inducing spikes that probably resultu. in the large output load swings. The governor vendor representative agreed with this conclusio On the afternoon of November 13. the licensee requested enforcement discretion from the NRC to extend the LC0 Action time by twelve hours to allow enough time to complete the maintenance and testing of the A DG (see Section 06.1). The licensee determined that additional testing beyond the normal surveillance testing would be necessary to verify DG operabilit In addition to the normal surveillance test. load rejection tests were performed to check performance of the A DG with regards to maintaining voltage and frequency under transient condition The licensee began surveillance testing of the A DG at 5:50 p.m. on November 13 and completed the testing at 11:20 p.m. The A DG was
,
declared operable at midnight on November 1 On Noverrber 21 at 1:40 a.m.. the licensee commenced the normal surveillance on the A DG. The frequency of the surveillance had been increased from monthly to weekly due to the DG failure. At 3:15 the A DG was secured due to large load swings of 1200 to 1400 kw when the-A DG was paralleled to the 115 kV grid. There were no grid
.'
instabilities identified that could have caused the large load swing Subsequent troubleshooting by the licensee identified high resistance in .
he contacts for a droop circuit relay. The relay was replaced and the -
- . . _ . _ . . _ . ._ _ . _ _ _ - _ . - ._ _
,
i
A DG was satisfactorily tested and declared operable at 2:10 p.m. on:
November 2 >
- The inspectors concluded that for each A DG event, the licensee had-corrected the DG problem and adequately tested the DG to establish operability. . At.the conclusion of the inspection period, the licensee had not determined the root cause of the problems with the A D The licensee's effort to identify the root cause and corrective action for-the A DG roblems will be followed and tracked'as an. Inspection Followup Item (IFI 50-395/97013 01.
' Conclusions-l The licensee identified and repaired the A DG on two occasions when it'
was found to be inoperable during routine surveillance testing. An IFI was opened to-followup on-the licensee's efforts to identify the root cause and corrective action for the A DG problems.
M2- Maintenance and Material Condition of Facilities and Equipment-
- M2.1 Surveillance-Observation
. Insoection Scoce-(61726).
The inspectors observed all or portions of the following surveillance tests. Most of these tests observed were infrequently performed surveillance procedure * Surveillance Test Procedure (STP)-215.003A. " Containment Isolation Valve Leakage Test for the CVCS, ND, RC, SF. SI, SP and WL
,
. Systems," Revision 3
- - STP-125.004. " Diesel-Generator Load Rejection Test." Revision 7
- STP-125.009, " Diesel Generator B Refueling Operability Test."
Revision 6
- STP-125.017, " Diesel- Generator A Loss of Offsite Power Test."
Revision 2
- STP-125.010, " Integrated Safeguards Test Train 'A." Revision 7
~
'* LSTP-125.011, " Integrated Safeguards Test Train B." Revision 7
- - - STP-501.0031"BatteryServiceTest," Revision 9
-
. STP-208.001. " Shutdown and Control-Rod Drop Test," Revision 6
,
i 1 9y -
me + 4--> , ,,+ ,. , y y y, __ g, ,
3 . ,,y_,_,
_
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4' Observations and Findina On October 29 and 30. the inspectors observed portions of integrated safeguards testing on trains A and B. per STP-125.010 and STP-125.011-respectively. The pre-job briefings )rior to the tests were thorough;
-
and involved all the participants. Tiere were no major deficiencies identified during the testing. The inspectors observed that the tests ;
involved significant coordination of different positions in the plant to =
obtain the required data. The tests were performed with all participants effectively obtaining dat The inspectors reviewed the results of surveillance test STP-501.003'
performed on the A and B train safety-related batteries. The batteries met the four hour load profile specified in the procedure. Final battery voltage exceeded the minimum allowable. The inspectors concluded from their review of the test results that the batteries were-operabl n November 5. the inspectors observed STP-208.00 All rods met-the
'
drop time requirement of 2.7 seconds. The pre-job briefing was thorough and covered the initial conditions for the test and the conduct of communications during the test. Clear communication between the reactor
'
l engineer and the control room t mervisor was necessary to successfully-perform the test. Consnunication was clear during the withdrawal of rods. Both the control room supervisor and the reactor operator closely- -
monitored for reactivity changes during rod movemen Conclusions Nine observed surveillance tests were 3erformed satisfactorily and in accordance with approved procedures. )ersonnel conducting the tests
.
demonstrated a good level of knowledge.
,
M2.2 . Conduct of Snubber Testina and Reolacement Insoection Scoce (61726F The inspectors monitored the licensee's progress to test and replace snubbers:in the plant during the refueling outage. During this efforts a significant number of-Condition Evaluation Reports (CERs) were generated to document conditions that were potentially adverse to quality, safety, or the reliability of the plant with regard to snubbers. : The inspectors selected three of these CERs to )erform an-in depth review to determine the adequacy of the report and tie resolution of the conditio b. : Observations and Findinas On October'20 the licensee wrote CER 97-1125 to document the-
' : inadvertent removal of-a snubber from the Safety Injection (SI) system during the removal of adjacent snubbers. The plant 'as w defueled and the
- SI system was not . required to be operable when the error occurred. The
. . . . . - . - _ - - _ _ - . . .
licensee determined that the removed snubber had been bench tested satisfactorily on October 17. Immediate action was taken to reinstall the snubber and perform a snubber reinstallation verification. The inspectors were satisfied that the licensee had taken appropriate corrective action to maintain snubber operabilit On October 14. the licensee wrote CER 97-1040 to document the testing of a charging system snubber that had failed its initial drag test during compression and locked u Prior to the in-plant visual test, lead blanket shielding was found draped over this snubber. It is not an
accepted practice to use snubbers as hangers for temporary shieldin An engineering evaluation of the snubber failure determined that a 5 mil runout existed between the ends of the snubber rod which was interfering with the pro)er operation of the snubber. It could not be determined if the rod was aent while in service or if it was machined out of cente The snubber was taken out of service and replaced with a strut under the snubber reduction program. An additional action was forwarded to HP for cause and corrective actions relative to the installation of shielding on snubbers. The inspectors considered these actions adequat On October 16. a Quality Assurance (0A) audit of snubber testing generated CER 97-1070 to document administrative deficiencies identified with the testing documentation. The deficiencies included obtaining preservice operational test data without an approved Surveillance Test Task Sheet (STTS) and an inappropriate use of the " retest" section of the STTS to document the performance of a preservice operational tes During the outage, due to ALARA considerations, the snubbers in the reactor building subject to surveillance testing were replaced with new snubbers when the installed snubbers were removed. Every snubber was replaced regardless of the subsequent surveillance test results. This made only one trip to each snubber location necessar The deficiencies identified by 0A involved the documentation of the test results for the new snubbers installed in reactor building. The licensee did not make any administrative changes to the snubber testing program to correct the 0A identified deficiencies and continued snubber testing using the established method to document the test results The inspectors reviewed the applicable snubber test procedures, reviewed a sample of completed test data sheets for new snubbers installed in the reactor building, and held discussions with plant personnel involved with snubber testing and the OA identified testing deficiencies. Based '
on these reviews and discussions.the inspectors determined that the actual snubber testing was performed satisfactorily. The inspectors had no concerns regarding the operability of the snubbers installed.in the
' plan However, additional NRC review is needed to determine if the licensee's administrative reautrements were satisfied for testing new snubbers installed in the reactor building. Pending additional review
,
. of the process for documenting test results for new snubbers, this issue is identified as an Unresolved Item (URI). This is identified as URI 50-395/97013-0 ... - _. __ . -. __ - ___ _
l 16 Conclusions !
Deficiencies in the method used to document snubber test results was identified in a 0A generated CER. The licensen made no changet in their testing process as a result of this CER. A URI was identified pending further review of the licensee's admmistrative process for testing new snubber to determine if appropriate action was take M2.0 Missed Electrical Surveillance Reauirement Insoection Scoce (617 5). .
The inspectors reviewed a missed TS surveillance requirement. The test i demonstrated the operability of offsite AC sources with the A DG inoperabl Observations and F1ndiriqi
]
On November 11. the A DG was declared inoperable when it failed the monthly surveillance test. With one DG Inoperable the TS LCO Action statement for TS 3.8.1.1.b.1, A.C. Sources. requires that operability of the AC offsite sources be demonstrated within one hour and at least once per eight hours thereafter. The licensee meets this surveillance requirement by performing STP-125.001, ' Electrical Power Systems Weekly Test.' Revision 1 On November 13, ths licensee nerformed STP 125.001. which was due at 12:15 p.m., 45 minutes late at 1:00 p.m. This surveillan,e test is performed by on shift 0)erations personnel, in this ca!.e the contrLi room operators responsi)1e for performing the test were distracted and missed the time the surveillance was next due. The test was performed immediately after it was identified that it had been missed. The licensee also verified with the load dispatcher that no breakers associated with electrical busses 10A and 108 had been cycled in the switchyard during the 45 minutes that the +.est was overdue. All the other recuired surveillance tests for the A DG inoperability were performec as required. The licensee is also evaluating methods to improve Operations tracking of non-routine surveillances performed in response to TS Action statement The inspectors concluded that the licensee had taken appropriate corrective action in response to the missed surveillance test. The system that the licensee uses to adhere to surveillance requirerrents for inoperable equipment normally works well. .The inspectors considered this to be an isolated failure to follow procedur This failure to follow the TS Acticn requirements of TS 3.8.1.1.b.1. A.C. Sources. -is identified as a Violation (VIO). This non repetitive, licensee identified and corrected VIO is being treated as a Non-cited Violation
.(NCV) consistent with Section VII.B.1 of the NRC Enforcement Polic This'is identified as NCV 50-395/97013-0 . . . -
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17 . (pnclusions-An NCV was identified for failure to meet an eight hour TS requirement !
to demonstrate the operability of AC offsite sources with a DG !
inoperabl l H2.4 . Inservice Insoection (ISI) i Insoection Scone (IP 73753) !
e D.0-in',pectors reviewed ISI programs, procedures, cnd recently !*
recanulated data for compliance to the 1989 Edition of ASME Section XI end Section 5.7 of the Updated Final Safety Analysis Repor ;
- Qbiprvations and Findinas -[
The commercial operation date for V. C. Summer was January 1, 1984: the l first 120 month inspection interval was January 1.1984, through December 31, 1993: and the current, second 120-month inspection interval i started January 1, 1994, and will end on December 31, 2003. Refueling :
Outage (RF0) 10. which just completed, was the first refueling outage, in the seccnd 40-month period, of the second 120 month interva ;
i The inspectors reviewed ISE-3, "ASME Section XI Inservice Examination Manual for 2nd Inspection Interval," Revision 1, the implementing
< program document for ISI. The inspectors also discussed the conduct and !
, results of the recently completed ISI inspections with OC personnel .
'
responsible for the ISI program.
. During the ISI inspection, the inspectors reviewed the details of two 3 piping system component failures. The first problem reviewed concerned -
by :
-dtofailure of a Weld be repetitive ofon the "A" earlier failures charging onpump"C" the pass line, charging which Tia pum a)peared '
second problem was the snubber failures described in LER 97-004 dated November 11, 199 (The charging pump weld failures are discussed i below, and the review of LER 97-004 is included in Section M8.3). ,
Nonconformance report (NCN) #97-1169, documented a weld leak on the "A" '
'
charging pump equalizing line. Another report. NCN #97-1178, documented ,
that the weld size for all the socket and fillet welds, on the "A" pum ,
chargin$
applica lea $HECoderequirements. equalizing line were undersized whe
The licensee's review of this problem disclosed that NCN #4398 dated -
January 7,:1992, and NCN #3656 dated January 18, 1990, documented similar occurrences on the "C" charging pump egualizing line. NCN #4398 ;
documented extensive vibration testing and analyses, conducted through a
'
-A)ril 1995, as the licensee attempted to understand the root cause of r tie repeated weld failures. The previous soc.ket weld failures have .
resulted in minor; leakage (weeping) which the licensee had identified and corrected prior to affecting pump operability. Additional 'eview of -
the problem disclosed a June 2. 1981 NCN documenting that the a ss, ,. ,y ,..r,,_.,e..,., , _ , , , . , _ . . ....w..m.,m_,, - - - . , ,%._,,_, ,. ,,_.,-,_,,. . _ . __ _ _ .. - .__- _
equalizing piping welds on the skid mounted charging safety injection pumps were undersized. The 1981 NCN had been closed out by an " accept as is' disposition, justified and signed by the construction Westinghouse Site Manager, Noting that the individadl weld failures had not created a safety ,
problem, and that the )roblem had been identified and dispositioned during construction. t1e licensee was in the process of evaluating long-term corrective actions. Two possible options were: 1) Modify the existing undersized welds to meet ASME Code requirements ar.d 2) Conduct surveillances during operator rounds and repair welds that leak. Based on the failure rate experienced to date. the inspectors concluded that '
either option was acceptabl Conclusions The ISI program was well organized, and on-track to complete the required inspections during the current 40-month inspection period.
M2.5 Steam Generator Insoection JnsoectionScooe(IP50002)
The inspectors reviewed the licensee's program for the completion of Technical Specification (TS) required eddy current testing of the steam generator tubing, Observations and Findinas The V. C. Summer steam generators were replaced during RF0 8. in October 1994. During RF0 9. in the Spring of 1996, tho licensee conducted eddy current, bobbin coil, testing of 22% of the tubes in steam generator A and 16% of the tubes in steam generator B. During the recently completed RF0 10. the licensee conducted eddy current. bobbin coil, testing of 30% of the tubes in steam generator C. During the inspection '
of steam generator C. the licensee also did rotating coil eddy current inspections of 100 tube sheet intersections. The rotating coil used was a multiple coil probe with a + Point coil and two pancake coil The eddy current signals of note during the inspection of steam generator C were minor dent signals at the top support plate, and some manufacturing burnish marks which had been recorded during the preservice inspection The licensee discussed plans to revise the steam generator inspection program to conduct eddy current and secondary side inspections of all three steam generators during the next refueling cutage. RF0 11. with the possibility of not doing any steam generator inspections during RF0 1 . .. ~- - . . . .
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c. Conclusions I The licensee continued to conduct a conservative eddy current inspection program on the recently replaced steam generator M2.6 Flow Accelerated Corrosion (FAC)
a. Insoection Scone (IP 49001)
The inspectors reviewed the licensee's program for measuring and predicting FAC in the power-conversion steam and water system b. Observations and Findinas The licensee's basic program for FAC utilized wear predictions from the use of the EPRI CHECMATE* program, sup)lemented by industry experience information. The CHECMATES model had )een updated with seven iterations of inspection data prior to the 1997 refueling outage. The licensee's engineer responsible for the FAC 3rogram used EXCEL * tables to com)are NDE thickness data. Because of t1e maturity of the licensee's CHEGATE8 model, the licensee had not felt the need to change to the WINDOWS based CHECWORKS$ progra During the 1997 refueling outage, the licensee inspected 51 locations in the steam, condensate, and feedwater systems with no required sample expansions due to unex)ected or unpredicted wear. The )iping replaced during the outage had )een predicted to be below wall t11ckness *
requirements by the FAC program, and piping spool pieces were prefabricated and staged prior to the outag c. Conclusions The licensee's flow accelerated corrosion program is a mature program that has been doing a good job of finding and replacing affected piping component M8 Miscellaneous Maintenance Issues (92902)
M8.1. (Closed) Licensee Event Reoort (LER) 50-395/96-04: unanalyzed condition regardinc reactor building line break analyre During integratea safeguards testing. Steam Generator (SG) water levels were observed to be increasing with the Emergency Feedwater (EFW) pum)s running and the EFW flow control valves closed. It was determined tlat this condition was not covered by the emergency operating procedures and may not be addressed in the safety analysis report. Emergency Operating Procedure (EOP) 3.0, Faulted Steam Generator Isolation. Revision 9, was revised to provide instructions to manually close the EFW header supply valves associated with a faulted SG During RF-10 the licensee performed maintenance on the EFW flow control valves to correct the leakage. This maintenance activity was documented in NRC Inspection Report No. 50-395/97012. During the inspection
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l
period, the licensee completed surveillance testing of these valves to verify the effectiveness of the maintenance. The inspectors reviewed the test data and concluded that the measured leak rate was within the acceptance criteria for all six EFW flow control valves. Based on these test results, the insped.oFs considered 1.he EfW system to have been returned to within the required analyzed condition.
M8.2 .(Ol ned) LER 50-395/97-05: missed surveillance on C charging /high head safety injection pump required by American Society of Mechanical Engineers (ASME) Code Section XI. On November 24. the licensee issued this LER to document a missed sorveillance on the C CCP, During RF-8 (Fall, 1994), the licensec testt. the C CCP at full flow conditions as required every 18 months. Vibration data taken during this test at the pum) outboard horizontal te.ct point indicated a vibration of 0.374 incies per second (ips).
In 1994, the licensee committed to the 1989 edition of the ASME Boiler and Pressure Vessel Code which referenced ASME/ ANSI OH-1987, " Operations and Maintenance of Nuclear Power Plants " addenda OMa-1988. This edition of the Code specifies that the acceptance criteria for vibration measurements is 2.5 times the reference value or 0.325 1ps. Due to the recent conversion to the OM Code, no reference values had been established for use during the RF-8 tests. The licensce's initial interpretation of these limits was that either value could be used as long as there was sound engineering judgement provided. During further review of this issue, the licenses determined that the limit should have been interpreted to mean the smaller of the two values. This being the case, the vioratir.n measurements taken during RF-8 would have required that tne pump vibration be considered in the Alert range and the surveillance frequency doubled to every nine months. Therefore, the missed surveillance occurred nine months after the completion of RF- The safety significance of the event was considered to be minimal because the two remaining CCPs were available during the majority of the time in question. The cause of this event was identified as personnel error. The licensee has revised the applicable procedure to more clearly specify the Code vibration limits. In addition, the licensee was in the process of reviewing vibration data for other Code related pumps to ensure that the limits had not been exceeded at any time since the conversion to the OM Standard. The inspectors considered these corrective actions to be adequat This failure to conduct required surveillance testing on the C CCP is identified as a Violation (VIO). This non-repetitive, licensee identified and corrected VID is being treated as a Non-Cited Violation (NCV) consistent with Section VII.B.1 of the NRC Enforcement Polic This is identif;ed as NCV 50 395/97013-04.
M8.3 (0 pen) LER 97-004: piping analysis exceeds code allowables due to snubber failures and failure to perform TS required snubber testin .
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This LER discussed two different events in one u nt report. The two events share common ground in that both events involved snubbers which were founa in the locked position during snubber reduction modification activities, but causal factors and corrective actions were significantly different. The *P1)ing Analysis Exceeds Code Allowables" portion involved snubbers tlat were in a degraded condition or the locked
)osition due to pre:".ature acina phenomena. The * Technical Specification Voncomplianca" portion of tfie LER involvea sout;bsrs that were in the locked position because they were damaged during a water hammer event.
The " Piping Analysis Exceeds Code Allowables" portion of the problem was discovered during snubber reduction activities in the 1997 refueling outage. An inoperable (locked) snubber found on an RHR line triggered failure analyses in accordance with TS 4.7.7 g. requirements. During the analysis of the snubber failures, a section of the Reactor Coolant System pressurizer spray line and a section of the steam generator blowdown piping were found to be ovcrstressed. Engineering analyses showed that the 31 ping supports had not been ourstressed. but that the effected piping lad been stressed beyond the ASME Code allowable values.
Ultrasonic examination of the spray line piping welds confirmed that there was no physical damag The blowdown piping was small diameter piping with socket welded connections that could not be ocndestructively examined to confirm that there was no weld damage, so the overstressed section of piping was replaced. As reported in the LER. additional fatigue analysis of the pressurizer spray line was being done by the NSSS vendor. Westinghouse, and generic root cause(s) analyses were being conducted for the failed snubbers.
Preliminary analyses of the failed snubbers showed that the locked condition was the result of aging phenomena, including fretting corrosion, brinelling, and lubrication deterioration. The reported phenomena were very similar to that described in NRC Information Notice 94-48: " Snubber Lubricant Degradation in High Temperature Environments."
The licensee was in the process of completing testing which could be used to update the information notice.
With respect to the " Technical Specification Noncompliance" portion of the LER, as a pcrt of the licensee's snubber reduction program, during installation of a mechanical strut as a replacement for Snubber MK-FWH-0353. (a PSA-10 mechanical snubber located on the B-loop. feedwater supply), the licensee found the snubber to be ino)eraH e. An evaluction of this snubber, as documented in NCN #97-0938, slowed that the damage to the snubber was the result of transient loads to the system exceeding .
the design loads of the snubber, similar to that caused by a water hamme Inspection of additional snubbers on the feedwater line resulted in the discovery of two more damaged snubbers. MK-FWH-0126 and MK-FWH-012 NCN #97-0938 references ONO. 94-98 which documented that a water hammer event had been recorded during start-up testing after the steam generator replacement outage in late 1994, An engineering evaluation, included in the disposition of NCN #97-0938. concludea that the transient loads that exceeded design loads were isolated to the area
_
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22 between Feedwater Check Valve D1684B and Feedwater Isolation Valve 01611 The three snubbers provided support for the portion of the feedwater system used to protect the code boundary in this are TS 3.7.7 states that snubbers on systems used to protect the code boundary shall be operable in Modes 1. 2. 3 and In addition. TS 4.7.7 requires that each snubber will be demonstrated operable by the performance of an augmented inspection >rogram. TS 4.7.7.c identifies one requirement of this program to be tlat at each refueling outage an inspection shall be performed of all the snubbers defined in TS 3. attached to sections of safety systems piping that have experienced unexpected, potentially damaging transients as determined from a review of o)erational data and a visual inspection of the systems. As stated in t1e LER, the snubbers in the feedwater system should have been inspected in accordance with TS 4.7.7 c. during RF0 9, April 15,1996 to May 23, 1996, due to the late-1994 water hammer being an " unexpected, potentially damaging transient".
The LER did recognize that when the unit returned to power after RF0 9, in the Spring of 1996, the licensee was in violation of the surveillance requirements of TS 4.7.7 Altnough the missed snubber surveillance was identified by the licensee, the inspectors, through a review of corrective action completed at the time of the inspection. concluded that the corrective action taken was not sufficiently comprehensive to prevent recurrence. In addition it was not clear whether the root cause of the missed surveillance had been identified. Not conducting the required snubber inspections during RF0 9 which resulted in the operation of the unit with inoperable snubbers is identified as ,
Violation 50 395/97-13-07, " Failure to Conduct Technical Specification Required SnubLer Inspections."
In addition, the combination of two unrelated snubber failure problems in one event report. LER 97-004, showed a lack of sensitivity to the issues being discussed. This combination of the two problems tended to minimize the importance of both problem II Enoineerina El Conduct of Engineering El.1 Westinahouse Fuel Performance i
a. Insoection Scone (37551)
The inspectors reviewed the licensee's Justification for Continued Operations Assessment for the performance of their nuclear fue b. Observations and Findinas On October 28. Westinghouse, the nuclear fuel vendor, informed the *
licensee that the current Westinghouse fuel development models indicate that margins to certain design criteria for. Westinghouse fuel have been
. . _ _ _ _ _ _ __
significantly reduced. Westinghouse stated that operating fuel regions may potentially exceed the pellet-to-clad gap reopening design criterion. The gap reopening criteria is a Wettinghouse fuel rod design criterion. With gap reopening, these fuel rods would also be susce)tible to exceeding the 17 percent local oxidation criterion (10 Cf150.46) following a postulated LOC Westinghouse performed a site specific assessment for the licensee to determine how these fuel issues could affect the current V. C. Summer cycle 11 fuel. The bounding fuel assemblies for the core were analyze Based on the Westinghouse models no fuel in cycle 11 was expected to violate the 17 percent local oxidation criterion. ,
An analysis was also performed to determine the burnup at which pellet-to-clad gap reopening could occur during cycle 11. It was determined, for the most limiting fuel assemblies, that gap reopening would not occur until a cycle 11 core average burnup of greater than 7.000 MWD /MT Other fuel in the core could experience gap reopening at an average burnup of 10.000 MWD /MTV during cycle 11. A burnup of 7.000 MWD /MTU is slightly less than a third of the expected cycle 11 total core burnu Based on the assessment's results it was concluded that the Sumer cycle 11 reload safety analysis and the Core Operating Limits Report (COLR)
were a)plicable, without any unreviewed safety questions, until 7.000 MWD /MTJ core average burnup. The fuel vendor is determining if any action is necessary to continue operation beyond 7.000 MWD /MT Conclusions Based on a review of a fuel performance assessment the inspectors concludec that there was no immediate concern that the current cycle 11 fuel was meeting the reload safety analysis.
E2 Engineering Support of Facilities and Equipment E2.1 Enaineerina Evaluation of CCP Seal Es1jilures
- Insoection Scone (37551)
The inspectors reviewed the licensee's engineering evaluation of the causes and corrective actions concerning the recent CCP seal failure Observations and Findinos On November 12. the licensee issued Abnormal Condition or Event Evaluation number 508 123 to determine the failure cause of the abnormally high number of CCP pump seal failures. The details of these failures are described in Section M1.2 of this repor A total of five seal failures were documented in this evaluation. The >
probable cause of three failures are described in detail while the cause
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of the remaining two failures was indeterminate. The ins)ectors considered the evaluation to be complete and detailed wit 1 all pertinent facts included. The conclusions and recommendations in the evaluation were reasonablo based on the fact c. Conclusions An engineering evaluation to determine the cause of five CCP seal failures was complete and detailed and included all relevant fact Reasonable conclusions were made based on these facts.
E8 Hiscellaneous Engineering Issues (92903)
E (Closed) UR" 50-395/97-02-04: lack of a 50.59 safety evaluation for inoperable 'eak detection sump level switches. The issue involved the leatage detection system being operated in a degraded condition due to three of the individual level switches (ISL01914. ISL01966 and ISLO1967) not being in service for extended periods of time. A review of the Final Safety Analysis Report (FSAR) identified the following areas of concern:
. FSAR Section 15.4.1.4.2. " Radioactive Releases from Recirculation Loops." stated, in ) art. "In addition, a 50 gpm (gallons per minute) leak from t1e failure of a passive component is assumed starting 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the accident and having a duration of 30 minutes."
. FSAR Section 6.3.2.11.2 " Leakage from Engineered Safety Features Systems Outside Containment." stated, in part. " Leakage approaching 50 gpm into an alarm drain or pump room sump is detected in less than one minute and actuates an alarm in the control room. Upon actuation of this alaru, the operator can determine which level probe caused the alarm and, thus identify which area housing ECCS (Emergency Core Cooling System) or reactor building spray system equipment is affected. The operator then takes the required action to isolate the leak "
The URI noted the plant had been operating since January 1996, with the leakage detection system configuration different than that described in the FSAR without the licensee performing a safety evaluation. Without a safety evaluation. it was not clear whether an unreviewed safety question existed. Also, the extent of the licensee's compensatory measures were not fully understood at the time of the inspectio During the current inspection period, the inspectors reviewed the above issues with licensee engineering and operations personnel. The inspectors also reviewed a licensee 10 CFR 50.59 safety evaluation dated May 30, 1997. which was performed to accept the failures of level alarms ILS01914 and ILS01967 until June 30, 1997. The inspection also included walkdom of selected plant areas where level switches were installed, additional reviews of FSAR and design basis documentation, aid review of
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operator actions for detection nf leakage alarm condition Documents reviewed included sections of: -
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- SAP-107. "10 CFR 50.59 Unreviewed Safety Question Review Process." >
Revision 1 j e NRC Generic Letter 91-18. "Information to Licensees Regarding NRC !
Inspection Manual Section on Resolution of Degraded and i
Nonconforming Conditions." Revision 1 i
e V. C. Summer Nuclear Station Design Basis Document (DBD), " Drains, !
Sumps, and Leak Detection," Revision 1 ,
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e V. C. Summer Nuclear Station DBD, " Radiation Monitoring System,"
Revision 3
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- FSAR Amendment 97-01, Section 6.3.2.11.2, " Leakage from Engjneered Safety Features Systems Outside Containment:" Section 15.4. ;
" Environmental Consequences of a Postulated Loss of Coolant !
Accident:" Section 12.1.4. " Area Monitoring:" Section 12.2.
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" Ventilation:" Section 12.3, " Health Physics Program " and !
Appendix 12A, " Design Review of Plant Shielding and Environmental i Qualification of. Equipment for Spaces / Systems Which May Be Used In ,
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Post Accident Operations Outside the Reactor Building at the Virgil C. Summer Nuclear Station," updated as of August 1997 -
- - Letter From NRC To Mr. O. S. Bradam " SUBJECT: Safety Evaluation OnConformanceToRegulatoryGuide197-V.C.SummerNuclear .
Station (TAC N0. 51137)," dated July 27, 1988 l e = Virgil C. Summer Nuclear Station Engineering Services Technical Requirements Package No. TRO-22. " Instrumentation With Only Seismic Requirements." Revision 5
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' * Drawing Number E-811-009. " Instrument Location Layout - Auxiliary Building.--Above Elevation 397' 0" - Southeast." Revision 5 e Operations Administrative Procedure (0AP)-106.1, " Operator Logs."' ,
Revision 6 t e _ Emergency Operating Procedure (EOP)-2.0, " Loss of Reactor or :
Secondary Coolant." Revision 9
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- - ~ Annunciator Response Procedure-(ARP)-001-XCP-606. Revisioi Change No.-E, Annunciator Point 3-4, "LD TRBL AB SMP/FLDRN JL HI" ,
Je- ARP-001-XCP-607. Revision 4 Change No F. Annunciator Point 3 4.
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. "LO TRBL AB SUMP /FLDRN LVL HI
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e' ARP-002-XPN-6032. Revision 1. Cha. ige No. B. Annunciator Point 1-5,
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'" Leak Detect RHR/CS Recirc VLV Area Alarm Drain 6 Level High" and
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Annunciator Point 3 3. " Leak Detect RHR Pump Room Sump Leakage > ;
45 GPM" e ARP-002-XPN-6033. Revision 3. Annunciator Point 3-3. " Leak Detect '
RHR Pump B Room Sump Leakage > 45 GPM" e 'ARP 019-XCP 645. Revision 1. Change No. B. Annunciator Point 2-1.
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"AB VENT DUCTS RH All HI RAD" ,
-The Inspectors reviewed the extent of the licensee's compensatory measures for the degraded level detection system, as identified in the a-original inspection. The. inspectors determined that, prior to the original ins)ection. Operations had implemented an increased awareness requirement )ased on guidance )rovided in 0AP-106.1 " Operating Logs".
.The inspectors reviewed the OA) and noted a requirement to perform ,
additional log readings for sorr.o alarm conditions. The licensee had *
1mplemented monitoring of Residual Heat Removal (RHR) sumps once per shift during the period. The inspectors reviewed selected operator logs and noted that the monitoring was documented. The licensee informed the ,
inspectors that these actions were not compensatory measures and that none were required 'or the inoperable . level switches. Based on this ;
review, the inspectors determined that compensatory measures had not been implemented for the degraded level detection instrumentatio However, operators had displayed increased sensitivity to the degraded >
conditions with log annotations of sum) conditions each shift. In addition.' the inspectors judged that tie guidance provided in GL 91-1 Revision 1, would not require the licensee to perform a safety .
evaluation for the degraded conditions discussed in the unresolved item >
since compensatory measures had not been implemented. Based on this review and the follosing discussion. URI 50 395/97-02-04 1s close Although the original unresolved issue, involving not conducting a '
safety evaluation had been resolved. the inspectors review of the safety evaluation conducted subsequent to the original inspection and .
walkdowns of the components in question, revealed potential design adequacy concerns with sump drains / alarm switches, as discussed belo ,
The inspectors noted, during review of the 10 CFR 50.59 safety evaluation tu accept the failures of level alarms ILS01914 and ILS01967, that the evaluation stated, in part. "The design basis function of the ;
= Leak Detection System in the Auxiliary Building is to provide: leakage i detection alarms for Engineered Safety Features Systems located-in the
- Auxiliary Building to enable operators to identify and isolate a post LOCA-(Loss of. Coolant Accident) Recirculation leak of 50 GPM within 30
. minutes to ensure the radiological consequences of post LOCA radioactive releases from the emergency core cooling system and reactor building .,
saray to'the Auxiliary Building is met as listed in section 15.4.1 of '
t1e FSAR. The failure of. level switches ILS01914 and ILS01967 does not prevent the.LD system from performing its design basis function, since ,
other Level Switches (ISL01965 for the RHR/ Waste Evaporator Sumps and LISL01911. 1913..and 1918 for the RHR/CS Recirculation area.....) are able to perform adequate leak detection functions to insure'the design- .
. basis of the. leak detection system is met." '
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The inspectors reviewed the basis for the safety eval ition conclusion that the proposed activity did not increase the consequences of an accident previously evaluated in the FSAR. The inspectors noted the evaluation stated. ' part. "The Waste Evaporator Sump level switch (ILS01965) will provide indication of a 45 to 50 GPM leak into eitner the *. or B RHR pump room sump within 9 minutes which would give operating >ersonnel 21 minutes to isolate the leak." The inspectors reviewed t11s justification (for ISL01967) and noted that even though the evaluation did not fully agree with the statement in FSAR Section 6.3.2.11.2. it provided reasonable assurance tha*. FSAR Chapter 15 requirements were met. The inspectors noted the licensee did not write a condition evaluation report to include the FSAR discrepancy into their corrective action progra However, the inspectors did not agree with the safety evaluation conclusion that the proposed activity did not increase the consequences of an accident previously evaluated in the FSAR for ILS01914 During plant walkdowns on November 17. 1997, the inspectors noted the floor in the auxiliary building room did not provide separation for the four sump drains / alarm switches. One of the alarm com)onents identified during the Maintenance Rule baseline inspection as )eing out of service for over 15 months was located in this area (ILS01914). The inspectors noted the May 30. 1997, safety evaluation stated, in part. "Alann Drain Level switches ILS01911. 1913 and 1918 are located in the same room (Auxiliary Building Elevation 397' RHR/CS RECIRC AREA) as ILS01914 and provide the necessary indicaticn of leakage in the area, and are able to perform adequate leak detection functions to ensure the design basis of the leak detection system is met." The inspectors questioned the licensee regarding the design of these level alarm sumps. The inspectors reviewed the DBD for the drains, sumps, and leak detection system. Section 3.8.2.4 of the DBD stated, in aart. "the alarm drain design allows a limited drainage flow of less tlan 25 gpm to drain from the floor drain through a 1 4" pipe. If in-leakage flows exceed the capacity of the 14" pipe, the water level rises and is sensed / alarmed by a level probe " Section 3.8.2.6 stated. in part. "The drain alarms are designed to alarm at 25 gpm ir.-leakage. This provides a 25 gpm margin relative to the 50 gpm rate assumed in dose assessments." The inspectors questioned how four drain alarm sumps in the same area (which could each acceat flows up to 25 gpm without alarming) could determine leakage approac11ng 50 g)m as outlined in the FSAR. Section 6.3.2.1 The licensee responded tlat other means of leakage detection were available including radiation monitors and tank level alarms. The inspectors noted that although these additional methods were available, the FSAR and DBD focused specifically on the level detection system as the primary means of identifying which area housing ECCS (Emergency Core Cooling System) or reactor building spray system equipment was affected so that operator action could-be taken to isolate the leak.
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28 l The inspectors identified to the licensee two questions associated.with :
this issue. The questions were: ,
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-e . Are the level alarm drains 1ocated in the auxiliary building
"RHR/CS Recirc Valve Area" desioned to detect a passive piping-failure condition which would alarm a cordition of icakage ;
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approaching 50.gpm?
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- Are the leak detection system components properly classified as non s3fety-related since their use appeared to be associated with *
ensuring 'he capability to prevent or mitigate the consequences of i dcci ants that could result in potential offsite consequences -i comp.*able to the 10 CFR Part-100 guidelines?
As stated in the cover letter of this report. the NRC requested that the *
1 Mensee provide a formal response to these questdons. Disposition of ,
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these issues is identified as an unresolved item. URI 50-395/97013-0 pending review of the licensee's response to the design basis issues !
relating to the leak detection system installed in the auxiliary ;
buildin ;
During the review of this activity, the inspectors noted that the licensee did not identify any of the items discussed as potential issues for inclusion into their corrective action program. The inspectors judgeo the licensee's threshold for formal identification of problems ,
'for the auxiliary building leak detection system in their corrective action program as a weaknes Jy. Plant Suooort .
R1 Radiological Protection ind Chemistry (RP&C) Controls R1.1 Genera 1Comnents l The inspectors observed radiological controls during the conduct of
. tours and observation of maintenance activities and found them to be acceptabl R1.2 Occuottional Radiation Exoosure Control Proaram
' Insoection Scooe (83750)-
The inspectors reviewed implementation of selected elements of the licensee's radiation protection program during the Refueling Outage-(RFO). The review included observation of radiological protection ;
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activities including: personnel exposure monitoring, radiological postings, verification,of posted radiation dose rates and contamination ,
levels within the RCA and a review of dose rate reduction techniques ,
through primary shutdown chemistry controls. Those activities were .
evaluated for consistency with the programmatic requirements, personnel '
monitoring requirements, occupational dose limits, radiological posting t
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recuirements. and survey requirements specified in Subparts B, C, F. anc J of 10 CFR 20 b. Observations and Findinos During tours of the RCA the inspectors noted that general - as and individual rooms were properly posted for radiological con. ion Posted survey maps were used to indicate dose rates and con Lmination levels at saecific locations within rooms. At the inspector's request, a licensee lealth Physics staff member performed dose rate and contamination surveys in several rooms and locations. The inspectors verified that the survey instrument readings were consistent with the dose rates and contamination levels recorded on the posted survey map The inspectors also noted that housekeeping was very good in the RC The inspectors reviewed licensee records of personnel radiation exposure and discussed ALARA program details, implementation and goals with the licensee. The annual site collective dose and individual exposures were compared to licensee's established ALARA goals and occupational dose limits, res?ectively. In additicn to Thermoluminescent Dosimeters (TLDs) whic1 were used as the primary device for monitoring personnel radiation exposure. Electronic Dosimeters (EDs) were used for monitoring the accumulated dose and the encountered dose rates during each RCA entry. As the individuals exited the RCA the accumulated dose and encountered dose rate information was transferred from the EDs to the Computerized Exposure Nuclear Tracking System iCENTS) data base in order to track individual exposure Based on the scheduled activities, daily and cumulative exposure projections were establishe Individual exposures, based on data from EDs and CENTS. were summarized by RWPs on a daily basis and allocated to the various orgaqizational department Daily reports of the collective and departmental exposures, along with their respective projected goals were issued for monitoring purpose Plots of daily and cumulative exposure vs. the.c respective projections were also distributed daily. The licensee provided the inspectors with records of personnel radiation exposure for Calendar Years (CY) 199 and Year To Date (YTD) 1997. The data presented in the table below was compiled by the inspectors for trending purposes from the current data provided by the licensee and from similar data contained in previous inspection reports. The licensee indicated that their overall objective is for their three year moving average of annual collective dose to be in the top quartile (when ranked in ascending order) of all PWR In order to meet that objective the licensee estimated that the annual collective dose for 1997 would only have to be less than 240 man-re However, based on scheduled activities a more conservative target goal of 90 man-rem was established as the annual goal. Prior to the start of the current RF0 the site collective dose was 12 man-rem, but as shown in the table the annual target and outage goals were exceeded as of day 21, i.e. October 24, of the planned 33 day outag The licensee estimated that the dose for the outage would approach 149 man-rem at the completion of the outag __ - _ _ . _ _ . _ . _ _ _ __ .
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Collective Dose (man-rem) j Annual Dose
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Outa9e Dose Year Actual Goal 3 Year Outa9e Actual Goal Da /s Mean Type
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1994 348 376 218 RF0-8 SGRP' 336 360 97 f
1995 10 10 212 1996 107 117 155 RF0-9 89 110-Satisfactory 39 95-Good 80-Exceptional 1997 139' 90
RFO-10 127' 95-Satisfactory 33 80-Good 60-Exceptional ,
-YTD 10/24/97 ' an 3 Steam Generator Replacement Project d
As of day 21 of 33 pl,st annedGoal (10/24/97)
The lice 1see also provided the inspectors with data from the CENTS pertaining to maximum individual radiation exposures for CYs 1994, 1995, 1996, and YTD 1997. Those data are tabulated belo _
Maximum Individual Radiation Doses (Rem)
Year TEDE Skin Extremity Eye Lens 1994 1.370 1.370 1.355 1.370 1995 0.292 0.292 0.292 0.292 1996 0.760 0.761 0.761 0.'i60 1997
1.050 1.050 1.050 1.050 Regulatory and Administrative Limits 10 CFR 20 5.000 50.000 50.000 15.000 Admi ,030 40.000 40.000 12.000
YTD 10/23/97
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The above administrative annual dose limits established by the license were delineated in procedure SAP-500. " Health Physics Manual". As
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' indicated-in the table, the maximum individual radiation exposures were wel'. within the licensee's administrative limits and the regulatory limits specified in 10 CFR 20.1201(a).
'The inspectors also reviewed licensee records for Personnel Contamination Events (PCEs) and uptakes of radioactive material The r
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licensee's records indicated that there were 69 PCEs this year 3rior to the start of the RF0 and 171 PCEs during the first 21 days of tie <
outage. Five of those events resulted in skin dose assignments of 1, 4, 86, 210. and 256 mrem. There had been 16 uptakes of radioactive i material, all since the start of the outage. Internal dose assessments
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were still in progress and preliminary estimates were that all were less '
than 5 mrem CEDE. The licensee also indicated that there had been no declared pregnant female workers this yea ;
The inspectors also reviewed the licensee's plans for )rimcry chemistry j controls during the reactor shutdown for the RF0 and t1e problems !
encountered during that process. The plans for the shutdown chemistry :
controls included early and more rapid injection of boric acid into the !
RCS during cooldown followed by injection of hydrogen peroxide after cooldown in order to cause the release of radioactive materials from the internal surfaces of the RCS. The plans also included maximizing the e letdown flow rate to the Chemical and Volume Control System sCVCS) and longer operation of the Reactor Coolant Pumps (RCPs) following cooldown in order to maximize the removal of the radioactive material from-the coolant. /pparently during the acid reducing phase of the proces .
after boration, much of the radioactive materials released from the '
metal surfaces inside the pressure vessel were in the form of insoluble ,
chemical compounds rather than soluble compounds which could be readily removed from the coolant by the CVCS demineralizers. Although 6500 -
curies (0.2 grams) of. Co-58 were removed from the system the insoluble materials were dispersed throughout the RCS. The RCPs were operated 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />. longer than the planned 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> but the rate at which activity was being removed from tne coolant had decreased and the dose rates from the RCS had stabilized. The general area and contact dose rates were generally twice the-levels. achieved during the previous RFO. In the lower elevations of the RCA the dose rates were several times higher that previous levels. This resulted in higher than expected exposures
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for workers during the outage and in the ALARA goal being exceeded half way through the-outage. The licensee indicated that assistance was -
being sought from vendors and industry research organizations in their efforts to determine the cause of the unexpected formation of the insoluble compounds,
' Conclusions Based on the above-reviews and observations the inspectors concluded ,
that the licensee was properly monitoring and controlling personnel radiation exposure and )osting area radiological conditions in accordance with 10 CFR ) art 2 Housekeeping in the RCA was very good during the RF0. Unexpected results from shutdown chenistry controls resulted in elevated dose rates from the RCS and outage ALARA goals >
-being exceede ,
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R4 Staff Knowledge and Performance in RP&C ;
i R4.1 f.Litt.1 in the Radiation Control Area , Insoection Scone (71750) ,
r On October 19, while conducting a routine plant tour, the inspectors observed an individual using a chewing tobacco product while in the RC !
b. ' Observations and Findinas
- During the inspection period, the inspectors conducted routine plant- '
tours-of all major areas including the RCA. On October 19. during one-of these tours, the ins)ectors observed an individual in the B chiller room using a chewing to)acco product. The B chiller room is located in '
the RCA and requires entry under a-Radiation Work Permit (RWP) or a Standing Radiation Work Permit (SRWP). Eating drinking, or smoking in the RCA is not permitted Decause of the increased potential to ingest >
contaminatio Entry into the RfA is through a portal located on the 412 foot level of the control building. A posted sign located at the RCA entry point provides general guidance and rules of practice for personnel in the RCA. One item on this sign states:
" Eating, smoking and drinking in authorized areas only." .
There are no areas in the RCA that are authorized for eating smokin :or drinking. Health Physics Procedure (HPP)-160. " Control and Posting of Radiation Control Zones." Revision 7.. requires all posted HP instructions be adhered to when conducting work s)ecified in a SRWP or a RWP. The individual Observed did not adhere to tie posting as required by HPP-160 This NRC 1dentified failure to follow posted requirements is identified as a violation (V10). This VIO is identified as 50-395/97013-0 c, Conclusions A VIO was identified for the failure to follow posted HP requirement .An individual was observed using a chewing tobacco product in the RCA.
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Si z Condvat of. Security and Safeguards Activities -
'S1;l General Comments (71750)
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- The inspectors observed security activities including compensatory measures during'tne conduct of plant tours. The inspectors observed
that-security had responded adequately to the increased activity during the refueling outag <
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. S1.2 Comoensatory Heasures l
.a. 'Insoection Scoce (81700) J Evaluated the licensee's program for compensatory measures of security
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equipment that was not functioning as committed to in Section 12 of the- !
Physical Security Plan (PSP) and appropriate procedures. This was to -
ensure that the implemented measures were equal or better than the >
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commitments made by the licensee.
' Observations and Findinas Four compensatory measures were being taken during the inspection period timeframe. Two were vital / protected area deficiencies and two were f
security equipment items not operating F. cording to procedural standards. Appropriate security measures compensated for the security deficiencies and inoperable equipm?nt. Measures consisted of the
- a) plication of specific procedures to assure that U1e effectiveness of i tie security system was not reduced. It was noted that the two :
vital / protected areas' compensatory measures had been in effect since early 1996. This was discussed with the licensee. The licensee said ,
that they were aware of this issue and it shoJ1d be resolved in the near i futur ;
- CQDelusions ,
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Through observations. Interviews, and documentation review, the
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inspectors concluded that the licensee used compensatory measures that -
ensured the reliability of security. related ecuipment and devices. This_ -
evaluation verified that the licensee employec compensatory measures
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when security equipment failed or its performance was impaire ;
S2 Status of Security Facilities and Equipment l
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S2.1 Protected Area Access Control
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' Insoection Scone (81700)
Evaluated the licensee's access control program for allowing packages and personnel to enter the protected area. This Las to ensure compliance with criteria in Sections 1. 3. and 4 of the PSP and appropriate Security Plan Procedures (SPP).
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b. -Observation and Findinas ,
The inspectors reviewed appropriate access control procedures to ensure that the. licensee provided appropriate access controls for the protected
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- area ;
Personnel, hand-carried )ackages or material, and delivered packages or l materials were searched )efore being admitted to the protected area, i Security personnel searched for firearms, explosives, incendiary ;
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devices, and other items that could be used for radiological sabotag i These searches were either by physical search or by search equipmen .
The inspectors-reviewed personnel access controls. A coded, numbere I picture badge identification system was used for personnel who were !
authorized unescorted access to the protected and vital areas. The !
codes corresponded to vital areas to which individuals had authorized !
access. Picture badges issued to nonlicensee personnel indicated authorized access areas and showed that no escort was require Personnel displayed their badges while within the protected are Visitors authorized escorted access to the protected crea were issued a badge that showed an escort was required, and were escorted by licensee-designated escorts while in the protected area. The licensee used t biometric hand geometry to ensure identification of individuals entering the protected are Access control program records were available for review and contained sufficient information for identification of persons authorized access -
to the protected area. The licensee maintained access records of key key cards, key codes, lock combinations, and other related equipment during a person's employment or for the duration of use of these item The inspectors evaluated control of the entry and exit of packages and material to the protected area. Security personnel confirmed the authorization of, and identified packages and material at the access .
control portal before allowing them to be delivered. The licensee used security force personnel, explosive and metal detectors, and X-ray equipment to identify and confirm that prohibited materian were not ,
entering the protected are t Conclusions-
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The Plant Security Plan (PSP) criteria for protected area access ,
controls for packages and personnel were being followe .
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52.2 Alarm Stations and Communications Insoection Scooe (81700) *
Evaluated the licensee's alarm stations and communication equipment to ensure that the application of the criteria in Sections 3. 6. 7. and 12 of the PSP and appropriate SPPs were implemented, Observations and Findinas The inspectors verified that annunciation of protected and vital- area alarms occurred audibly and visually in the alarm stations. The licensee equipped both stations with Closed Circuit Television (CCTV) .
assessment capabilities and communication equipment. Alanns were
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. tamperfindicating and self-checking.. and provided with an uninterruptable power supply. These stations were continually manned by capable and knowledgeable security operators. The' stations were F
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independent-yet redundant in operation. Alarm stations' interiors were not visible from the protected area, and no single act could remove the capability of calling for assistance or otherwise responding to an alarm. Alarm stations' walls, doors, floors, and ceilings were bullet-resistan The inspectors evaluated the equipment, operation, and maintenance of -
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internal and external security communication links. and determined that they were adequate and appropriate for their intended function. Each security force member could communicate with an individual in each of the continuously manned alarm stations. who could call for assistance from other security force personnel and from local law enforcement ,
agencies. The alarm stations had the capability for continuous'two-way voice communication with local law enforcement agencies through radio and the conventional telephone service. The licensee had compensatory measures for defective or inoperable communication equipmen Conclusions The licensee was complying with the criteria in the PSP and Security Plan Procedures for alarm stations and communicati'.;n equipmen S2.3 Protected Area Detection and Assessment Aids insoection Scone (81700)
Inspect the licensee's protected area intrusion detection systems and assessment aids to verify that they were functionally effective and met licensee commitments in Sections 3 and 4 of the PSP and appropriate SPP Observations and Findinas The licensee had installed intrusion detection systems that could detect attempted penetrations through the exterior isolation zones. and attempts to gain unauthorized access to the protected area. The licensee segmented the intrusion detection systems into enough alarm zones to provide adequate coverage of the protected a*ea perimeter barrier and isolation zones. The detection aids and alarm devices, including transmission lines, were tamper-indicating and self-checkin . Sensors continued to function normally during loss of normal power. The licensee had com detection aids. pensatory measures The inspectors to replace found through defective document or inoperative review and observation that the licensee had installed and tested detection and/or surveillance subsystems for the protected areas. The systems consisted of motion and volumetric detection equipment to discover and assess unauthorized activities and conditions. These systems sent alarm conditions to response force personnel though the alarm stations allowing for response force personnel to assess and correct the
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condition The licensee provided means for monitoring and observing, by human eye - !
or CCTV. persons and activities in the isolation zone and exterior areas ,
within the protected area. These means provided for assessing intrusion ;
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alarms for possible threats occurring in the isolation zone and exterior areas within the protected area. The transmission and control lines used in the CCTV intrusion alarm assessment system had line supervision '
and tamper indicatio Conclus'gn ;
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The licensee's intrusion detection systems and assessment aids were
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functional, well maintained, effective for both covert and overt !
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penetration attempts, and met licensee commitment .4 Testina and Maintenance Insoection Scooe (81700)
Evaluated the licensee's program for testing and maintenance of security equipment. This was to ensure the reliability of physical protection-
related equipment and security-related devices; and the licensee's compliance with the criteria in Section 12 of the PSP Security
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Maintenance Procedure (SMP) No. 002. " Explosive Detection Equipment.~
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Revision 4: SMP No. 003. "X-ray Detector Equi) ment." Revision 5: and ;
SMP No. 011. "Perifeld-M Perimeter Detection Equipment." Revision 0.
. Observa.tions'and Findinas The licensee's program for testing and maintenance of security equipment was established to ensure that physical protection-related equipment met the i aeral performance recuirements. -Personnel were permanently assigned to the testing anc maintenance of security related devices and equipment..Each intrusion alarm was tested at the beginning and end of '
any period in which it was used and at least every seven days during continuous use. Alarm station operators tested the comunication i equipment required for onsite communication at least at the beginning of each security work shift. Comunication equi communication was: tested at least once a day.pment required for offsite
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The inspectors observed the quarterly testing and subsequent
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maintenance, if needed, of the-X-ray and explosive detectors at the Personnel Access Portal, and the Perifeld-M equipment. The 7-day tests
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for-16 vital area doors, 5 protected area zones. 6 duress alarms, and
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Vehicle Access Portal controls were. observed also. Each area / item tested was.found operable according to documented comitments.
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a Conclusions ,
The licensee has programs to ensure the reliability of security. related-equipment and devices. The testing and maintenance program was a 4 strength in the security progra i S3 Security and Safeguards Procedures and Documentation ;
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S3.1 Security Proaram Plans Insoection Scooe (81700) -
Reviewed the appropriate sections of Amendment 40 and 41, d6ted April ,
and July 1997.-of the PSP 4:1d Amendment 14 and 15. deted June 1997, of the Training and Qualification Plan (T&QP).
, Observations and Findinas The inspectors reviewed the amendments to verify compliance to the requirements of 10 CFR 50.54(p). Amendment 41 changes mostly involved
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the demolition of the original Primary Access Portal and redesignating !
the Secondary Access Portal as the new Primary Access Portal. Amendment !
40 changes involved clarification and additions to the Vehicle Barrier ;
System. Amendment 14 changed the hand held weapons * qualification course from the National Rifle Association Modified Police to the Federal Bureau of Investigation Qualification course. Amendment 15 changes were enhancements to and clarifications of existing commitments that did not decrease the safeguards effectiveness of the T&O Conclusions Changes to the PSP and T&OP did not appear to decrease their !
effectivenes ,
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S3.2 Security Events loas ,
- Insoection Scoce (81700)
Evaluated and verified that the licensee-appropriately analyzed, tracked, resolved, and documented safeguards events that the licensee determined'did not require a report to the NRC within one hou , Observations and Findinas The' inspectors reviewed four quarterly Safegua"ds Event Logs, starting-with'the fourth quarter of 1996 to the third quarter 1997 and the fourth .
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quarter 1997 events logged up to the date of the inspection. During this period; 89 events were logged. Hardware events were 44 percent an Human Errors were 56 percent of the totals. The October-November 1997 ,
outage. accounted _ for 22 percent of the events. The most reported events ,
.were human error involving unsecured vital area doors'. 21 percent (11 l
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- during-the outage), and hardware problems with security doors 20
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percent (5 during the outage). Excluding the outage, the range of events per quarter was 8 to 19. With 20 events occurring during the outage. it appears that the fourth quarter 1997 will be a high quarte events for the first month and a half of the quarter. However, peaking during an outage is not unusual, due to the number of transit contractor / vendor personnel onsite during an outage, c. Conclusions Safeguards events were being appropriately analyzed tracked resalved, and documented.
SS Security Safeguards Staff Training and Qualification 55.1 Trainina Records a. Insoection Scoce (81700)
Interviewed security personnel and reviewed security personnel training and qualification records to ensure that the criteria in the T&OP were me b. Observations and Findinas The inspectors interviewed 9 security non-supervisor personnel. 4 supervisors, and witn?ssed approximately 15 other security personnel in the performance of their duties. Members of the security force were knowledgeable in their responsibilities, plan commitments and procedures. Eleven randomly selected training records, four supervisors and seven non-supervisors, were reviewed by the inspectors concerning training, firearms, testing, job / task performance and requalificatio The inspectors found that interviewed armed response personnel had been iretructed in the use of deadly force as required by 10 CFR Part 7 F < ;ers of the security organization were requalifjed et least every 12 months in the performance of their assigned tasks. both normal and contingenc This included the conduct of ohysical exercise requirements and the completion of the firearms course. Through record review and interviews with security force personnel, the inspectors found that the requirements of 10 CFR 73. Appendix B. Section concerning suitability, physical and mental qualification data, test results and other proficiency requirements were me Conclusions The security force was being trained according to the T&OP and regulatory requirement __ _
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~ Manaaement Meetinas ;
XI -Exit Meeting Summary The inspectors preser.ted the inspection results to members of licensee
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management at the conclusiM of the inspection on December 5,1997. TO- i licensee acknowledged the findings presente l The inspectors asked the licensee whether any materials examined during i the inspection should be considered proprietary. No proprietary ;
information was identifie :
- PARTIAL LIST OF PERSONS CONTACTED
Licensee l F. Bacon, Manager. Chemistr Services L. Blue. Manager. Health Ph sics S. Byrne General Manager, uclear Plant Operations .
R..Clary Manager. Quality Systems M. Fowlkes. Manager. Operations S. Furstenberg, Manager. Maintenance Services ,
D. Lavigne. General Manager. Nuclear Support Services :
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G. Moff att. Manager. Design Engineering K. Nettles. General-Manager. Strategic Planning and Development
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H. O'Qu' ... Manager, Nuclear Protection Services :
- A. Rice Manager. Nuclear Licensing and Operating Experience i G. Taylor. Vice Pres' dent. Nuclear 0perations 1
- A. Torres. Supervisor. Quality Assurance .
R. Waselus. Manager.. Systems and Component Engineering J. Wasieczko. Supervisor. Security Operations R. White, Nuclear Coordinator. South Carolina Public Service Authority '
B. Williams. General Manager. Engineering Services G. Williams. Associate Manager. Operations .
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INSPECTION PROCEDURES USED
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IP 37551: Onsite Engineering *
IP 49001: Inspection of Erosion / Corrosion Monitoring Programs :
IP 50002: Steam Generators :
'IP 61726: Surveillance Observations ;
IP 62707: Maintenance Observations !
IP 71707: Plant Operations .
IP 71750: Plant Support-Activities
~IP 73753:~ Inservice Inspection i IP 81700: Physical Security Program for Power Reactors .
=IP 83750:- Occupational Radiation Exposure Control Program
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IP 92902: Followup - Maintenance .
-IP 92903: Followup - Engineering ,
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ITEMS OPENED. CLOSED. AND DISCUSSED
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'Doened- f 50 395/97013-01 IFI licensee's effort-to identify the root cause and f corrective action for the A DG problems (Section f M1.6) l
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50-395/97013-02 URI pending review of the failure to make ;
administrative changes to the snubber testing-program (Section M2.2) ,
, 50-395/97013-03 NCV failure to follow the TS Action requirements of TS 3.8.1.1.b.1. A'.C. Sources (Section M2.3)
'50-395/97013-04 NCV failure to conduct required surveillance testing i on C CCP (Section M8.2)
50 395/97-13 07
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VIO Failure to Conduct Technical- Specification '
Required Snubber Inspections (Section M8.3)
50 395/97013-05 URI' review of licensee response to design basis
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issues relating to the leak detection system ;
installed in the auxiliary building (Section
.E8.1)
50 395/97013-06 VIO- failure to' follow posted HP requirements
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(Section R4.1)-
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50-395/96-04 LER- 'unanalyzed condition regarding reactor building l line break. analyses (Section M8.1) !
150-395/97-05 -LER missed surveillance on C charging /high head-
- safety injection pumpf(Section M8;P.)
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50-395/97002-04 URI lack of a 50.59 safety evaluation for inoperable leak detection sump level switches (Section E8.1)
50-395/97013 03 NCV failure to follow the TS Action requirements of TS 3.8.1.1.b.1. A.C. Sources (Section M2.3)
50-395/97013-04 NCV failure to conduct required surveillance testing on C CCP (Section M8.2)
Discussed 50-395/97-004 LER Technical Specification Noncompliance and Pi)ing Analysis Exceeds Code Allowables Due to Snub)er Failures (Section M8.3)
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