IR 05000277/1999001
| ML20205C001 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 03/25/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20205B995 | List: |
| References | |
| 50-277-99-01, 50-277-99-1, 50-278-99-01, 50-278-99-1, NUDOCS 9904010050 | |
| Download: ML20205C001 (40) | |
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! U. S. NUCLEAR REGULATORY COMMISSION l
REGION I
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l License No DPR-44 <
- DPR-56 -
l Report No l
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Docket No Licensee: PECO Energy Company
- Correspondence Control Desk i P.O. Box 195 i Wayne, PA 19087-0195 ;
Facility: Peach Bottom Atomic Power Station Units 2 and 3 Inspection Period: January 5,1999 through February 15,1999 Inspectors: A. McMurtray, Senior Resident inspector M. Buckley, Resident inspector B. Welling, Resident inspector D. Dempsey, Reactor Engineer ,
C. Welch, Reactor Engineer G. Smith, Senior Security Specialist L. Eckert, Radiation Specialist Approved by: Curtis J. Cowgill, Chief Projects Branch 4 Division of Reactor Projects l
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9904010050 990325 PDR ADOCK 05000277 G PDR ,
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t- f-EXECUTIVE SUMMARY
- Peach Bottom Atomic Power Station l
NRC Inspection Report 50-277/99-01,50-278/99-01 This inspection report included aspects of licensee operations; surveillances and maintenance; engineering and technical support; and plant support area Operations:
l- * Station corrective action processes were effective in identifying and resolving significant L conditions adverse to quality. Problem identification was good for significant issues under the Performance Enhancement Program (PEP) process, but inconsistencies were
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noted in the identification and reporting of lower-level issues under lower tier reporting systems. Most investigations were thorough and completed in timely manner. Problem resolution was generally effective. However, inspectors noted a backlog of corrective action items awaiting reviews for adequacy. Station management stated that they had recognized some shortcomings :in the corrective action processes and had begun improvement initiatives. (Section 07.1)
! e The Nuclear Review Board provided good independent discussion and evaluations of the topics presented during the February 4,1999 meeting. The questions directed to the presenters by the members of the Board during this meeting were probing and insightfu (Section O7.2)
Maintenance:
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e The Unit 3 high pressure coolant injection (HPCI) on-line outage work was well planned with an effective post-maintenance test. Although the station retumed the HPCI system l to an operable status within technical specification requirements, problems with the
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gland seal condensate pump resulted in the HPCI outage being extended past the
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original schedule. (Section M1.2)
e The station has effectively incorporated the probabilistic risk assessme.t individual plant evaluations for core damage frequency and large early release frequency into the planning of system outages and assessment of plant risk due to emergent work. (Section M8.1)
Enaineenna:
e in five instances, nonconformance report dispositions for motor-operated valve (MOV)
anomalies were narrowly focused. Although operability determinations for the valves l l were acceptable, the causes of the anomalus conditions, such as lubrication i degradation, were not addressed or evaluated for corrective action. PECO was j implementing corrective actions to address MOV program deficiencies. (Section E2.1) {
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Executive Summary (cont'd)
l e PECO performed a comprehensive assessment of new information regarding motor- ;
operated valve (MOV) output capability contained in Limitorque Technical Update 98-0 '
Operability determinations used best available industry data for calculating motor actuator performance capabilities and used reasonable technical assumptions. Planned long-term corrective actions appropriately addressed restoration of MOV design margin (Section E2.2)
l * A significant leak on the Unit 2 high pressure coolant injection (HPCI) system gland seal l l condenser was caused by an inadequate maintenance procedure. This Severity Level IV violation is being treated as a Non-Cited Violation consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as PEP 10009358. (Section E3.1) l e Engineering troubleshooting and investigation efforts following the significant leak on the Unit 2 high pressure coolant injection system gland seal condenser resulted in effective i
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corrective actions. However, operations and engineering had missed opportunities, prior l to the leak, to identify the cause of the abnormal high pressure coolant injection system response. (Section E3.1)
Plant Sucoort:
e The licensee established, implemented, and maintained effective programs for performing surveillances of station ventilation systems and calibrations, tracking and trending and maintaining system reliability for the effluent / process radiation monitoring systems. (Section R2)
e Generally, movement of the contaminated filters from the spent fuel pool to the shipping cask was performed well with good radiation technician monitoring and oversight and good ALARA awareness and actions by the workers. The inspector observed a slow response to an area radiation monitor alarm. (Section R4.1)
e The licensee established, implemented, and maintained an effective program with respect to response to audit findings and quality control for validating measurement results for radioactive effluent samples. (Section R7)
e The licensee was conducting security and safeguards activities in a manner that pr;tected public health and safety in the areas of alarm stations, communications and protected area access control of personnel and packages. This portion of the program, as implemented, met the licensee's commitments and NRC requirements. (Section S1)
e Security facilities and equipment were determined to be well maintained and reliabl Security procedures were being properly implemented. Security staff knowledge, i performance and training were determined to be acceptable. Security organization and l administration were adequate to ensure effective implementation of the progra (Sections S2 through S6)
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TABLE OF CONTENTS EXECUTIVE SU M MARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii TABLE OF CONTENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv
' Summary of Plant Status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1. Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 01 Conduct of 0perations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 01.1 General Com ments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 O2 Operational Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . . . . 2 O2.1 Equipment Status Control improvement Initiatives . . . . . . . . . . . . . . . . 2 O2.2 Unit 3 High Pressure Coolant Injection (HPCI) System Walkdown . . . 3 05 Operator Training and Qualification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 05.1 Operator Training for Shutdown Cold Over-Pressure Transients . . . . . 3 05.2 Change in Corrective Action Commitment Date for Violation (VIO) 50-277(278)/98-11-02 Documented in NRC Inspection Report . . . . . . . . . 4 07 Quality Assurance in Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 07.1 Corrective Action System Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 07.2 Nuclear Review Board Meeting (71707) . . . . .... ...... .......7 08 Miscellaneous Operations issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 08.1 (Closed) Violation (VIO) 50-277(278)/98-01-01 . . . . . . . , . . . . . . . . . . 7 08.2 (Closed) VIO 50-277/98-01 -02 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 08.3 (Closed) VIO 50-277/98-01 -03 . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . 8 08.4 (Closed) VIO 50-277/98-01 -05 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 08.5 (Closed) Licensee Event Report (LER) 50-277/2-98-009 . . . . . . . . . . 9 11. M a i nte n a nce . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 l M1.1 General Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 M1.2 Unit 3 HPCI Scheduled Maintenance Outage . . . . . . . . . . . . . . . . . . 10 M8 Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 M8.1 Use of PRA Techniques During Plant Work Activities . . . . . . . . . -. . . 11 M8.2 (Closed) LER 50-278/3-98-005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 M8.3 -(Closed)VIO 50-278/98-01 -06 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 I l l . Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 E Establishment of Site Engineering Response Team (ERT) . . . . . . . . 13 E2 Engineering Support of Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . . 14 E Motor-Operated Valve Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 E2.2 Limitorque Technical Update 98-01 for AC Motor-Operated Valves . 16 E2.3 Motor-Operated Valve Motor Pinion Gear Key and Clutch Failuree . . 17 E3- Engineering Procedures and Documentation . . . . . . . . . . . . . . . . . . , , . . . . 19 iv f
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l E HPCI System Gland Seal Condenser Leak (Unit 2) and (Closed) LER 2 -
99-001 ............. . ...... . . .......... ..... .. . 19 E4 Engineering Staff Knowledge and Performance . . . . . . . . . . . . . . . . . . . 21 E Failure of Unit 2 Reactor Building Damper in the Stsndby Gas Treatment System to Automatically Open on Demand . . . . . . . . . . . . . . . . . . . . 21 E Understanding of the 3D-MONICORE Computer Program by Reactor E ng i nee ring . . . . . . . . . . . . . . . . .........................22 E8 Miscellaneous Engineering issues . . . . . . . . . ....... .. .........23 E (Closed) Inspector Followup item (IFI) 50-277(278)/97-02-07 . . . . . 23 E8.2 (Closed) LER 50-277/2-98-006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 E8.3 (Closed) Unresolved item (URI) 50-277(278)/97-06-02 . . . . . . . . . 23 l IV. Plent Su pport . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .................. 24 R2 Status of RP&C Facilities and Equipment . . .... .............. . . . 24 R2.1 Calibration of Effluent / Process Radiation Monitoring Systems (RMS),
Calibration of Flow Rate Measuring Devices, and Calibration of Hydrogen Monitors . . . . . . . ......... .................... ........ 24 R2.2 Air Cleaning Systems (84750) . . . . . . . . . . . . . . . . . . .........25 i
R4 Staff Knowledge and Performance in RP&C . . . . . . . . . . . . .. .........25 R4.1 Removal of Contaminated Filters from the Unit 3 Spent Fuel Pool . . 25 l R7 Quality Assurance (QA) in RP&C Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 i
R8 Miscellaneous RP&C lssues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 R8.1 Offsite Dose Control Manual (ODCM) Revision 11 (84750) . . . . . . . . 27 R8.2 Noble Metals Addition (84750) . . . . . . . . .. ... ...... .. . . 27 l S1 Conduct of Security and Safeguards Activities . . . ....... ..........,27 i S2 Status of Security Facilities and Equipmant . . . ......................28 i S3 Security and Safeguards Procedures and Documentation . . . . . . . . . . . . . 29 S4 Security and Safeguards Staff Knowledge and Performance. . . . . . . . . . . . 30 S5 Security and Safeguards Staff Training and Qualifications (T&O) . . . . . . . . . 31 S6- Security Organization and Administration . . . . . . . . . . . . . . . . . . . . . . . . . 31 i
! V. Management Meetings . . . . . . . . . . . . . . ........... .................. 32 X1 Exit Meeting Summary . . . . . . .. .. ...... . .. ..... ........ 32
- ATTAC H M E NT 1 . . . . . . . . . . . . . . . . . . . . . ... .... .. . .... .. ........ .33 t
l l Attachment 1 -Inspection Procedures Used l - ltems Opened, Closed, and Discussed
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- List of Acronyms Used v
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Report Details
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[ Summary of Plaat Statug l PECO operated both units safely over the period of this repor Unit 2 operated at 100% power throughout this inspection perio Unit'3 operated at 100% power throughout this inspection period. .
l. Operations
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01 Conduct of Operations'
l l O1.1 General Comments ' Inspection Scope (71707)
Several newly licensed reactor operators and senior reactor operators stood watches in the control room during the inspection period. The inspectors observed their performance end discussed plant issues and equipment challenges with the j i Observations and Findinos i l
The inspectors obssrved that the new reactor operators were attentive to their duties and control panels and exhibited very good three part communications, alarm response, and alarm response card (ARC) usage. The inspectors also observed good procedural usage and peer and self checking, when required. New senior reactor operators maintained appropriate command and control of activities and managed control room access, as necessary. New reactor operators and senior reactor operators were cognizant of any issues affecting the units and of degraded plant equipment. The inspecto,15 concluded that the new reactor operators and senior reactor operators performed well with good monitoring and alarm response on the units and appropriate usage of three part communications and operations procedure Conclusions Overall, newly licensed reactor operators and senior reactor operators performed well, with good monitoring and alarm response on the units and appropriato usage of three part communications and operations procedures.
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Topical headings such as 01, M8, etc., are used in accordance with the NRC t.tandarolzed reactor inspection report outline, individual reports are not expected to address all outline topics.
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O2 Operational Status of Facilities and Equipment O2.1 Eouloment Status Control Imorovement Initiatives Insoection Scooe (71707) 1 The inspectors reviewed the new Equipment Status Control Action Plan (ESCAPE)
initiative at the station. This included observing an ESCAPE meeting involving several managers at the station, reviewing "The New Events" briefing sheet, watching the new turnover video, and discussing various other improvement initiatives with depanment directors involved with the ESCAPE progra Observations and Findinas Senior station management established the ESCAPE initiative to address several equipment mispositioning issues that occurred during 1998. Although the Operations department was not in charge of this initiative, they were actively involved in determining causes and solutions for these problems. Most station departments were involved with ESCAP j The station noted that there were approximately 92 configuration control incidents in 1998. Most of these incidents were of minor significance and did not involve safety-related systems . The inspectors documented the more significant incidents in NRC '
Inspection reports 50-277(278)/98-06,98-08, and 98-1 The inspectors noted after discussions with department directors and review of the ESCAPE kick-off meeting results that several causes were identified for previous equipment mispositioning issues. Many mispositioning events occurred when work activities were transferred between work groups, especially during the restoration of plant equipment to the normal operating status. Weaknesses were identified with tumovem, pre-job briefs, and some administrative processee and procedures used to l conWI work activities. The inspectors noted that the ESCAPE initiative has helped to j l me.xe statica personnel aware of the extent of the problems with equipment status control and how they were directly involved with several equipment mispositionings. The daily station newsletter, "Today @ Peach Bottom Atomic Power Station," was used to
> communicate developments with ESCAPE and to heighten the awareness of the issue to all station personnel. A briefing sheet, called "The New Events," has been developed to inform maintenance personnel about recent equipment status control events. A new video showed personnel the attributes and techniques to use to conduct a good effective . turnover.
l Conclusions PECO initia!3d a new Equipment Status Control A.: tion Plan (ESCAPE) to focus the station on areas that have been identified as weaknesses in equipment status contro This plan was intended to make station personnel aware of the extent of equipment i
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- mispositioning events and the actions that were being developed to address the causes of these event .2 Unit 3 Hiah Pressure Coolant Iniection (HPCI) System Walkdown Insoection Scooe (71707)
The inspectors performed a walkdown of the Unit 3 HPCI system and compared the actual system configuration with that described in drawings and the system check-off lis Observations and Findinos The inspectors found the system properly aligned to perform its safety function. No significant discrepancies in configuration control on the Unit 3 HPCI system. Minor problems, including a non-environmentally qualified (non-EQ) cabinet door being left partially open, a missing gage giass on an air-operated valve pressure regulator and an incorrect component label were discussed with operators. The inspectors also observed a minor difference between Units 2 and 3 in the configuration of the HPCI gland seal condenser Conclusions The inspectors found the Unit 3 high pressure coolant injection system properly aligned to perform its safety functio Operator Training and Qualification 05.1 Operator Trainina for Shutdown Cold Over-Pressure Transients Inspection Scooe (71707)
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The inspectors reviewed the plant Operational Transient (OT) procedure that the station credited with preventing a potential non-design basis cold overpressure transient. The inspectors also discussed the initial and requalification training requirements for this issue with Operations training managemen Observations and Findinas Information Notice 97-63 and Generic Letter 98-05 informed licensees about allowed relief from inservice inspection requirements for the volumetric examination of circumferential reactor pressure vessel welds. During the NRC review of this issue, it was identified that a cold over-pressure transient represented enough of a significant risk that it should be addressed if relief was requested from the inservice inspection requirements. Peach Bcttom was granted relief from inservice inspection requirements for the Unit 2 circumferential reactor pressure vessel welds on December 2,1998. In the submittal from Peach Bottom, the licensee noted the risk to the units of a cold over-pressure transient was low due to operator training and plant-specific procedures that I
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provided adequate instructions to prevent this transient. The inspectors reviewed OT-110, Revision 6, " Reactor High Level" procedure and the reactor coolant system (RCS)
pressure-temperature limit curves shown in the technical specification The inspectors noted based on discussions with Operations training management that initial licensed operator training provided fundamental training on brittle fracture and vessel thermal stress, main steam and pressure relief, OT-110, and the RCS pressure-temperature limit curves. Licensed operator requalification training provided experience in monitoring the RC3 pressure-temperature limit curves and using OT-110 on the simulator. The inspectors noted while reviewing OT-110 and the technical specification RCS pressure-temperature limit curves, that OT-110 focused on responding to an unexpected rise in reactor level at power. Although the instructions in OT-110 would prevent a cold overpressure accident by controllinq reactor level, it did not contain specific information given by the technical specification RCS pressure-temperature limit curves for low temperature conditions. The cuives showed that between 70*F and
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110*F that vessel pressure must not exceed 312 psi The inspectors determined that monitoring of the reactor pressure and temperature by reactor operators during shutdown condition provided adequate detection capability of a i potential cold overpressure transient. The inspectors also determined that training of Operations personnel and OT-110 provided adequate protection to prevent a cold overpressure transien c, Conclusions Adequate detection and prevention capabilities exist for a cold overpressure transient due to training of Operations personnel and station operating procedures for responding to an unexpected rise in reactor leve .2 Chanae in Corrective Action Commitment Date for Violation NIO) 50-277(278)/98-11-02 l
Documented in NRC Inspection Renort l j
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In NRC Inspection Report 50-277(278)/98-11, the inspectors documented that the ;
licensee intended to have A-C-10, " Operator Licenses" revised by the end of February l j 1999. This revision was part of the corrective action to prevent recurrence of part of VIO j
- 50-277(278)/98-11-02. The licensee informed the inspectors that this revision would not j l be issued until the end of April 1999 due to delays in reaching agreement on the change !
l with cognizant Limerick station personnel. This was a common procedure used by j
! Peach Bottom and Limerick. The inspectors reviewed this commitment change and discussed the change with cognizant regional supervision. The inspectors and regional j supervision had no concerns with the new April 1999 procedural revision dat l
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07 Quality Assurance in Operations l l
07.1 Corrective Action System Review i a.- Insaar%n Scope (71707)
The inspectors performed a limited review of the station corrective action processe . The major focus was on the Performance Enhancement Program (PEP); although some inspection of lower-tier, departmental corrective action systems was also accomplishe The inspectors reviewed a sample of both completed and in-process PEP reports and discussed them with station personnel. Also, the inspectors interviewed several l members of the station staff on the implementation of the correction action processe ,
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I Observations and Findinas !
Problem identification The inspectors determined the PEP process was effective in identifying significant l conditions adverse to quality. PEP was used primarily to identify the higher level !
problems. Less significant, precursor issues were typically documented in non-PEP departmental corrective action system With respect to the departmental corrective action systems, problem identification in i some systems was inconsistent. For example, some maintenance work groups initiated significantly fewer in-Process Maintenance improvement System (IMIS) entries than
, other work groups with similar workloads, relying on peer or supervisory coaching rather than documenting IMIS items. Maintenance management recognized that inconsistency ;
in problem identification reduced the effectiveness of the departmental trending i processes in identifying adverse trends and was taking action to provide consistency among the work group Based on interviews, the inspectors determined that the threshold of a PEP item was not i well-defined. Station personnel did not always have a clear understanding of the thret. hold between PEP and lower-tier corrective action processes. While lower level, precursor issues could be reported as a PEP according to the program guidanm, most of these issues were documented in other departmental corrective action sys v The inspectors noted that the PEP process occasionally did not identify potentially adverse trends when multiple equipment problems occurred. Examples included multiple cold-weather related problems documented in NRC inspection report 50-277(278)/98-11, and several motor-operated valve problems that occurred during refueling outage 2R12 (a PEP was initiated after inspector questioning). Section E2.1 l of the report describes some of these valve problems.
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Investiaation and Analysis Based on personnel interviews and reviews of a number of PEl' reports, the inspectors determined that PEP lasue Review Leaders (PIRLs) were knowledgeable of investigative techniques for PEP investigations; in general the signif' cant issues (Class A investigations) were detailed and thorough. Investigations of moderately significant (Class B) issues varied considerably in scope. The inspector reviewed a sample of the
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Class B issues and concluded that they were acceptable. Investigations were generally )
completed on a schedule consistent with the significance of the issu ]
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With respect to PEP tracking and trending, the inspectors noted that Experience
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Assessment personnel did not assign cause codes in a consistent manne Consequently when the inspectors performed searches for problems with similar causes (e.g. failure to follow procedures) the tracking syctem did not identify all such problem ]
The inspectors noted adequa'.e tracking and trending of lower-tie reporting system I For example, the inspectors noted that compilations of Event-F ., Operations and IMIS data provided useful information to both the work groups and managemen Problem Resolution in general PEP reports reviewed by the ins,;ectors included detailed, planned corrective actions that addressed the causes and other issues identified in the investigations. The due dates for the planned corrective actions were generally commensurate with the safety significance of the issu The inspectors observed that some of the Class A PEPS (full root cause analysis) did not have corrective actions for all %tified causes and contributing causes as required by the PEP program guidanca. PECO independently recognized this situation and was taking actions assure that PEP program guidance was me While PEP assigned corrective actions were generally completed in a timely manner, the independent review to verify the adequacy of completed actions received low priorit The inspectors noted that about 350 corrective action items were awaiting reviews for adequacy. Further, the inspectors observed that some of these were over a year ol Current initiatives i
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The Experience Assessment Group stated that they had begun a number of initiatives to l improve the process and enhance its implementation. These included:
- Developing " threshold documents" to define thresholds and inter-relationships between PEP and lower-tier corrective action systems
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Generating new PEP performance indicators tailored to individual work groups, to improve accountability ;
a Directing Experience Assessment personnel to take a more active role in ;
investigations
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f. 6 7 Conclusions Station ccrrective action processes were effective in identifying and resolving significant conditions adverse to quality. Problem identification was good for significant issues under the Performance Enhancement Program (PEP) process, but inconsistencies were noted in the identification and reporting of lower-level issues under lower tier reporting systems. Most investigations were thorough and completed in timely manner. Problem resolution was generally effective. However, inspectors noted a backlog of corrective action items awaiting reviews for adequacy. Station management stated that they had recognized some shortcomings in the corrective action processes and had begun improvement initiative .2 Nuclear Review Board Meetina (71707)
On February 4,1999, Nuclear Review Board (NRB) Meeting #355 was held at Peach Bottom. The inspectors observed portions of this meetin Peach Bottom plant management discussed events that have occurred at the station during recent months and department directors discussed improvement initiatives in
' Operations and challenges in the current Corrective Action syste The inspectors observed good independent discussion and evaluations of the topics presented. Several probing and insightful questions were directed to the presenters by the members of the NRB. The inspectors concluded that the NRB provided an independent review of operations of the station as described in Appendix D of the Updated Final Safety Analysis Report (UFSAR) during this meetin Miscellaneous Operations issues O8.1 (Closed) Violation (ViO) 50-277(278)f98-01-01 Inadeauate Verification of Alarm Acknowledament Due to Control Room Supervisor Leavina Work Station Without Relief In January 1998, the inspectors observed that the control room supervisor was outside of the designated main control room work station area for several minutes with no temporary relief or designated individual for control room oversight. During this time an expected annunciator alarm came in that was acknowledged by the reactor operator but was not verified by a control room supervisor as required the Operations Manual. The inspectors noted that this was an example weak oversight of control room activitie The inspectors noted that OM-P-3.2, " Senior Licensed Operators," was changed to 1 require that the control room supervisor obtain temporary relief prior to leaving the designated main control room work station area. The inspectors have observed substantial improvements in control room oversight, verification of reactor operators acknowledgment of alarms and overall performance of personnelin the control room since the middle of 1998. These improvements were the results of the "Back to Basics" and other initiatives implemented by station and Operations management in 1998. The inspectors have no further concerns with this issu n
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08.2 (Closed) VIO 50-277/98-01-02 Missed Technical Soecification Surveillance Reauirement
. Test for Verification of Proper Flow in the Recirculation Looos On January 3,1998, operations personnel discovered that the Unit 2 reactor operator (RO) failed to perform the technical specification (TS) surveillance requirement for verification of proper flow in the recirculation loops following start-up. The root cause of this deficiency was unclear wording in the surveillance test (ST) procedure that mislead the RO into believing that he did not have to perform this surveillance until 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after l the unit was operated above 25% reactor thermal power.
I l The inspectors verified that the ST was revised to clarify when the verification of proper l flow was required following start-up. The inspectors also noted that both units have been shutdown and restarted several times since this deficiency occurred and no instances of failure to perform this TS surveillance requirement have been identified.
, The inspectors have no further concerns with this issu .3 (Closed) VIO 50-277/98-01-03 Missed Technical Soecification Surveillance Reauirement I
Test for Verification of Core Flow as a Function of Thermal Power On January 3,1998, operations personnel discovered that the Unit 2 RO failed to i perform the TS surveillance requirement to verify that core flow as a function of I THERMAL POWER was in the " Unrestricted" region of TS Figure 3.4.1-1 following start-up. The root cause of this deficiency was unclear wording in the ST procedure that mislead the RO into believing that he did not have to perform this surveillance until 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the unit was operated above 25% reactor thermal powe The inspectors verified that the ST was revised to clarify when the verification of core i flow as a function of THERMAL POWER was required following start-up. The inspectors
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also noted that both units have been shutdown and restarted several times since this def;ciency occurred and no instances of failure to perform this TS surveillance requirement have been identified. The inspectors have no further concems with this ssu .4 (Closed) VIO 50-277/98-01-05 Unexpected Trio of Unit 2 Main Turbine Durina Start-uo On January 1,1998 during Unit 2 reactor start-up, the main turbine was inadvertently rolled to a speed of 1400 rpm and it tripped on main oil pump low pressure. An instrument and control (l&C) testing procedure did not contain instruction to reset the speed select at the electro-hydraulic control panel following completion of l&C work on December 31,1997. The control room operators did not reposition the speed select during unit start-up and failed to notice that the turbine was rolling for over two hours prior to the trip. The licensee identified that incomplete procedures, lack of effective l plant monitoring, and lack of a questioning attitude by workers were the three apparent l causes of this even The inspectors verified that the l&C testing procedure and normal plant start-up f procedure were changed to verify that the electro-hydraulic controls were in the proper l
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position to support start-up. The inspectors have also observed significant improvements in procedural adherence, control board monitoring, and questioning attitude by operations personnel following implementation of the "Back to Basics" and other improvement initiatives by station and Operations management. No similar issues have been identified during several start-ups of both units that occurred during 199 The inspectors have no additional concerns with this issu .5 ; Closed) Licensee Event Reoort (LER) 50-277/2-98-009 Unolanned Enaineered Safety Feature Actuations Resultina from a Transformer Insulator Failure ;
On December 27,1998, the failure of a transformer insulator resulted in the loss of the 2 Emergency Auxiliary Transformer which caused a trip of the 2SU-E breaker and de-energization of the 2SU bus. This resulted in Primary Containment Isolation System Group ll isolation; a engineered safety feature activation, on both unit The inspectors conducted an on-site review of this LER including the corrective action In addition to the corrective actions documented in NRC Inspection Report 50-277/(278)/98-11, the licensee discussed the original bus bar and cable support with the vendor. The vendor noted that this configuration and alignment could cause the transformer insulator failure that occurred. In addition, the licensee reviewed the scope and interval of transformer and protective relay preventive maintenance (PM) tasks and decided to shorten the performance frequency and add insulator inspections to the transformer PM activities. No additional concerns were identified by the inspectors during this revie II. Maintenance M1 Conduct of Maintenance M1.1 General Observations NRC Inspection Procedures 62707 and 61726 were used in the inspection of plant i maintenance and surveillance activities. The inspectors observed and reviewed i selected portions of tl'e following maintenance and test activities:
l Maintenance Observations: Observed On:
i Replace RCIC Turbine Exhaust Rupture Disks, C0184832 January 11,1999 MO-2-13-131 Motor Operator PM, R0726092 January 11,1999
' Electrical inspection Tests for 3B RHR Pump Motor, R0749979 January 25,1999 investigate & Repair HPCI PCV, C0185755 February 1,1999 inspect & Refurbish Vogt Lift Chk. Vivs. (HPCI), M-510-106 February 1,1999 Surveillance Observations: Observed On:
ST-O-13-301-2 RCIC Pump, Valve, Flow and Unit Cooler January 13,1999 Functional and in-Service Test
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ST-O-23-301-3 HPCI Pump, Valve, Flow and Unit Cooler February 4,1999 Functional and in-Service Tes ST-O-014-306-2 Core Spray Loop B Pump Valve, Flow and February 15,1999 I Cooler Functional and in-Service test The work and testing performed during these activities was professional and thorough, i
. Technicians were experienced and knowledgeable of their assigned tasks. The work and testing procedures were present at the job site and actively used by the technicians and operators for activities observed. Good pre-job briefs were observed prior to the performance of the surveillances observe M1.2 Unit 3 HPCI Scheduled Maintenance Outaae Insoection Scope (61726 & 62707)
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The inspectors reviswed selected documentation and observed work for the scheduled, HPCI maintenance outage to verify the licensee conducted these activities in a manner sufficient to ensure reliable, safe operation of the plant and plant equipmen Observations and Findina l l
The licensee took the Unit 3 HPCI system out-of-service for a four-day planned !
maintenance outage on January 31,1999, with the unit at 100% power. The maintenance work included replacement of the gland seal condensate pump. Generally, the work was well planned and schedule ,
The inspectors observed that the new gland seal condensate pump did not run properly during the initial post maintenance testing (PMT) and that the PMT was aborted. The licensee decided to reinstall the original gland sea' condensate pump with a new moto A leaking packing gland, that was to be corrected by installing the new pump, remained when the old pump was reinstahed. The licensee's evaluation of the problem with the !
new gland seal pump was still on-goin '
The HPCI system performed satisfactorily during the PMT following the gland seal pump work and the system was returned to operable on February 6,1999. Although the HPCI system was returned to operable within technical specification requirements, problems with the gland seal condensate pump resulted in the HPCI outage being extended past the original schedul Conclusion i
The Unit 3 high pressure coolant injection (HPCI) on-line outage work was well planned with an effective post- maintenance test. Although the station returned the HPCI system to an operable status within technical specification requirements, problems with the gland seal condensate pump resulted in the HPCI outage being extended past the onginal schedul l
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M8 Miscellaneous Maintenance issues M8.1 Use of PRA Techniaues Durina Plant Work Activities ADection Scoce (37551. 62707 & 71707)
, The inspectors reviewed the licensee's on-line risk management process to determine
how it was incorporated into the work planning process and discussed the risk management process with the work week managers and other licensee personnel. The ,
inspectors also reviewed the individual Plant Evaluation (IPE) to determine how closely it J l matched the on-line risk assessment.
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l Observations and Findinas i
j The licensee updated the Individual Plant Evaluation (IPE) Level I and ll for both units at
- Peach Bottom Atomic Power Station in May 1997. The IPE results were incorporated 3 l into a software program called Sentinel. The Sentinel program is used to evaluate l l system configurations during on-line maintenance to determine the impact on plant ris l
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When updates were made to the IPE, the Sentinel program was also update l L The removal of equipment and systems from service were modeled by the Sentinel program to determine the core damage frequency (CDF) and the large early release l'
frequency (LERF). The worst case CDF or LERF was generated by these calculations for use in planning equipment outages. Fire suppression or detection and support systems for safety systems were not modeled by the Sentinel program. Work control personnel were required to determine that removal of support systems rendered safety systems inoperable prior to using Sentinel.
l The Sentinel output was reviewed by the work week manager to see how changing plant l configuration affects risk. The work week managers were responsible' for rescheduling
- work or other activities found to be unacceptable to overall ris '
L i For technical specification equipment, the work week managers limited scheduled outage time and required jobs to be worked 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> a day. Generally, work week managers plan work so that only one safety system was planned to be out of service at a time, even in cases where Sentinel determined that the risk of removing additional systems was lo The inspectors noted that the licensee has minimized equipment outage times during scheduled maintenance. Sentinel was being used to assess the risk during these outage periods. Although, the system manager's knowledge of Sentinel was not l comprehensive, Engineering management recognized this issue and intended to provide j additional training in this are Although initially the inspectors noted that the control room operators were not receiving risk assessments from the work week managers, the work week managers started distributing these assessments to the control room during this inspection. The inspectors l
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discussed the risk assessments with the operations personnel and noted that control j room personnel were aware of these assessments and understood the increase in risk l when these systems were removed from servic ]
The inspectors determined through observations of the work week managers that the i Sentinel program was being effectively incorporated into the control of on-going work week planning for scheduled surveillances and removal of equipment from service. The Sentinel program was also effectively updating plant risk due to changes in plant configuration and emergent work activities, Conclusion The station has effectively incorporated the probabilistic risk assessment individual plant !
evaluations for core damage frequency and large early release frequency into the ,
planning of system outages and assessment of plant risk due to emergent wor l
M8.2 (Closed) LER 50-278/3-98-005 Inadvertent Unit 3 Electrical Bus E33 Trio Durina Performance of Unit 2 Electrical Bus E32 Surveillance Test On October 25,1998, the Unit 3 E33 bus was inadvertently tripped during the ;
performance of a Unit 2 surveillance procedure. As noted in NRC Inspection Report 50-277(278)/98-10, the inspectors determined that inadequate self-checking and peer ;
checking by the instrument and control technicians caused this event. The inspectors also did not identify any inadequacies with the Unit 2 surveillance procedur The inspectors performed an on-site review of the LER and PEP for this event including corrective actions initiated. Corrective actions included making changes to impreve self-checking and peer checking effectiveness and guidelines in maintenance administrative procedures. The inspectors noted that maintenance management has focused on improving peer checking and self-checking by maintenance personnel in 1999. Also, the licensee has started a procedural improvement initiative that should provide better human factor barriers in procedures for all groups at the plant including instrument and control. After this event, the inspectors observed instrument and control technicians performing a surveillance test using the same panels involved in this event. The technicians were differentiating relays using different colored tape to ensure that the correct relays were used during this test. The licensee performed a risk assessment of this event and determined that it had a negligible impact on (CDF) since the E33 bus was unavailable for only six minutes during this emnt. The corrective actions for this issue were adequate. The inspectors had no additional concerns with this issu M8.3 (Closed) VIO 50-278/98-01-06 Unit 3 Exceeded Licensed Power Level Due to Inaccurately Calibrated Feedwater Temoerature instruments NRC Inspection Report 50-277(278)/98-01 cited a violation of the Unit 3 operating license for exceeding the licensed power level by as much as 0.6% for a period of about 18 months. This condition occurred as a result of inaccurately calibrated feedwater temperature instrument .
13 The inspectors reviewed the corrective and preventive actions documented in the PECO responces to the Notice of Violations dated June 3,1998, and September 22,199 These actions included revising seventeen surveillance procedures to address potential impact on the plant and requiring reviews when calibration adjustments are made. Also, administrative guide AG-CG-108, " Response to Report of Measuring and Test Equipment Out-of-Tolerance," was revised to provided additional detail and expectation The inspectors verified that these actions were completed by reviewing several procedures. There have been no similar events in which inaccurately calibrated equipment affected heat balance calculations or core thermal power levels. The inspectors concluded that the corrective actions implemented by PECO were effectiv Ill. Enaineerina E1 Conduct of Engineering E1.1 Establishment of Site Enaineerina Response Team (ERT) Insoection Scope (37551)
In January 1999, site engineering management established a site Engineering Response Team (ERT) to focus on resolving emergent plant issues. Site engineering management discussed this initiative with the inspectors Observations and Findinas Establishment of the ERT was intended to allow site system mviagers to better focus on plant reliability and long term equipment health. The ERT was staffed by both design engineers and system managers. The ERT manager was designated as the Engineering Duty Manager (EDM) during tha day from Monday through Friday throughout the year. The ERT was designed to be the primary engineering interface for the Fix-It-Now (FIN) team. The ERT was fully functional by February 8,199 i The inspectors noted that the ERT should help address previously identified concerns of troubleshooting of degraded plant equipment. The inspectors concluded that the ERT was a very good site engineering initiative. This initiative was designed to provide dedicated engineering resources for emergent plant issues and allow system mangers to focus on improving plant equipment reliability and monitoring long term equipment trend Conclusions in January 1999, site engineering management established a site Engineering Response Team (ERT) to provide dedicated resources for resolving emergent plant issues. This initiative was developed to allow system mangers to focus on improving plant equipment reliability and monitoring long term equipment trends. This effort should help address concerns about engineering support for troubleshooting of degraded equipmen p
14 E2 Engineering Support of Facilities and Equipment I
E Motor-Operated Valve Problems J insoection Scope (92903)
NRC Inspection Report 50-277(278)/98-10 documented several motor-operated valve (MOV) failures during the 1998 Unit 2 refueling outage, and concluded that there had been a negative performarme trend in PECO's Generic Letter (GL) 8910, " Safety-l Related Motor-Operated Ver Testing and Surveillance," program. The inspectors -
- reviewed nine nonconformance, reports (NCRs) from 1997 and 1998 conceming various
! MOV problems to assess the licensee's operability determinations, causal evaluations,
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and corrective actions. The inspectors also evaluated the MOV tracking and trending i program and the interactions between the component engineering group and the MOV maintenance tea Observations and Findinas Nonconformance Reports :
l Eight of the nine NCRs reviewed discussed instances in which the output thrust of ( various MOVs either exceeded or did not meet the required values during as-found l diagnostic tests. While the valves remained operable, the inspectors determined in five i cases that PECO did not completely address the causes of the problems. NCR 98-00251 documented that reactor core isolation cooling (RCIC) steam supply valve MO-3-l 12-131 underthrusted due to a damaged stem and degraded stem / drive sleeve interfac Stem lubrication was inadequate, the clutch housing grease had hardened, and the l motor-actuator grease showed indications of breakdown. The conditions partly were l attributed to the high temperature environment of the valve. The licensee corrected the nonconforming conditions, but did not address the causes of the lubricant degradation in its corrective actions. For example, the need to increase the lubricant inspection or preventive maintenance frequencies due to the harsh environment were not evaluate Other underthrust conditions involved 'B' low pressure coolant injection (LPCI) to drywell
- . spray valve MO-3-10-26B r V7-02940), and feedwater recircu!ation valves MO-3-06- A/B (NCRs 97-02873 a- "72). In these cases, maintenance increased the i torque switch settings to remurc .;utput thrusi to within specifications. Engineenng provided acceptable justifications for the increased settings and as-left torque and thrust
- values, but did not consider the causes of the large decreases in output thrust that l occurred since the last diagnostic tests, and did not evaluate future operability should the
! degradation mechanism (s) persist uncorrecte NCR 98-02542 documented an as-found underthrust condition of high pressuro coolant injection (HPCI) discharge valve MO-2-23-19. During the early stages of trouble shooting, prior to engineerir;g becoming involved, maintenance focused on degradation of the actuator motor that had been documented previously. Subsequently, engineering determined the cause to have been inadequate preventive maintenance (lubrication) of r- ]
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the thrust adapter. The thrust adapter is unique to old-style SMB-4T motor actuators, of which there are six at Peach Bottom. The licensee identified the five additional actuators, j but did not initially evaluate existing test data to determine whether the performance of those valves might alsofie degrading. During the inspection, PECO performed the evaluation and concluded that performance had not changed significantly between diagnostic test Common Specification NE-145, " Selection of NRC Generic Letter 89-10 Program Valves and Differential Pressure Testable Valves," requires evaluation and adjustment of stem lubrication frequencies based on operating and service conditions and/or stem factor (or thrust) degradation rates observed during performance monitoring and trendin Pursuant to GL 96-05, " Periodic Verification of Design-Basis Capability of Safety-Related Motor-Operated Valves," a new procedure, A-C-81, "PECO Motor-Operated-Valves," will ,
require annual re-assessment of stem lubrication effectiveness. The inspectors l concluded that implementation of these specifications as part of PECO's GL 96-05 #
program acceptably addressed the most likely cause of the MOV performance problem The licensee also agreed that some of the NCR dispositions had been narrowly focused and included the finding as an evaluation item in an independent assessment of the MOV program planned for the first quarter of 199 Trackina and Trendina Proaram After each refueling outage, a report is generated that compares as-left diagnostic test results with minimum and maximum thrust and torque acceptance criteria and specified torque switch settings. The rep 3rt was used to identify nonconformances or candidates for margin improvement. However, the report wa:: not effective in identifying generic trends associated with the various degradation mechanisms common to MOVs, such as ,
stem and actuator lubrication. Since PECO did not have a user-friendly system for i
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sorting the causes of MOV performance problems among the safety-related valve population and identifying overall trends, PECO was developing a " desk top MOV trending guideline" in accordance with procedure A-C-81 to provide this capabilit GL 89-10 Proaram Performance l PEP 10009188 was issued after the last Unit 2 refueling outage to capture the lessons leamed from GL 89-10 program activities during the outage. PECO concluded that a decline in program performance had occurred. However, that conclusion was not assigned a formal evaluation in the PEP. The licensee informed the inspectors that PECO planned to complete an in-depth evaluation of the program within the next month to assess the technical and programmatic issues. Following implementation of corrective actions, the licensee intended to have an independent party perform an effectiveness review. By the conclusion of the inspection, PECO added an evaluation item to the PEP to document and track the effor n .
l 16 Conclusions ,
I In five instances, nonconformance report dispositions for motor-operated valve (MOV)
- anomalies were narrowly focused. Although operability determinations for the valves were acceptable, the causes of the anomalous conditions, such as lubrication degradation, were not addressed or evaluated for corrective action. Programmatic actions to evaluate current lubrication practices against environmental conditions and MOV performance trends under PECO's periodic verification program were planned, but had not yet been implemented. PECO was implementing corrective actions to address MOV program deficiencie E2.2 Limitoraue Technical Uodate 98-01 for AC Motor-Ooerated Valves -
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. l jnspection Scope (90700)
l The inspectors reviewed PECO's evaluation of Limitorque Technical Update (TU) 98-01,
" Actuator Output Torque Calculation." The TU revised the industry guidance for )
determining the output torque capability of Limitorque motor actuator !
1 Observations and Findinas l l
TU 98-01 changed previous guidance for sizing Limitorque motor-actuators by disallowing the use of run efficiency and requiring use of an application factor (AF - l typically 0.9) for all supply voltage conditions greater than 70% of nominal voltage. Also, three specific actuator configurations required additional evaluation, either through actual I test data, specific validated engineering data, or Limitorque certified calculation data, to i ensure that they were sized properly for the intended applications. The loss of design ;
capability potentially could result in failure of a valve to operate under design basis !
conditions or failure of the torque switches to trip resulting in motor stal ,
PECO's response to the TU was documented in nonconformance report (NCR) 98-01514. The design calculations of 74 motor-operated valves (MOVs) used run efficiency and/or an AF of 1.0 as design inputs. After recalculating the design thrust requirements in accordance with the TU, PECO idantified 13 noncenforming MOVs due to the loss of run efficiency and 12 nonconforming MOVs due to including the new AF. In addition, five MOVs were identified with susceptible motor-actuator configurations (60 foot-pound, 1800 rpm, Frame 56 attemating current motors) that required additional evaluation. The licensee performed operability evaluations for the valves that utilized, in part, the methodology for calculating motor output torque capability c'ocumented in Commonwealth Edison's (CECO) White Paper 125, " Installed Motor Capability Evaluation," Revision 2, dated October 14,1995. The methodology was developed following an extensive valve actuator motor testing program, and represented the best
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available industry data for the tested motor types. The inspectors verified that PECO implemented the methodology appropriately in a sample of the operability calculation Additional assumptions regarding environmental and motor heatup effects and long-term degraded voltage conditions were reasonable. The licensee was unable to demonstrate that the torque switch for residual heat removal (RMR) loop test valve MO-3-10-34B
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would prevent moter stall under degraded voltage conditions. Therefore, when out of the safety position during suppression pool cooling or during RHR pump full flow testing, the valve was considered to be inoperable and the appropriate technical specification action statement was entere Long term corrective actions included performance of motor heatup analyses to remove excess conservativism in the current design assumptions for motor torque loss, planned implementation of hardware changes or torque switch adjustments, and evaluation of certain valves for margin irnprovement. The inspectors considered these actions to be appropriat Conclusions PECO performed a comprehensive assessment of new information regarding motor-operated valve (MOV) output capability contained in Limitorque Technical Update 98-0 Operability determinations used best available industry data for calculating motor actuator performance capabilities and used reasonable technical assumptions. Planned long-term corrective actions appropriately addressed restoration of MOV design margin E2.3 Motor-Operated Valve Motor Pinion Gear Kev and Clutch Failures Inspection Scope (92903)
The inspectors reviewed PECO's corrective actions in response to MOV motor pinion gear key and clutch failures and Limitorque Maintenance Update 89-0 Observations and Findinas MOV Failures Motor pinion gear key failures occurred in 1998 on core spray loop 'A' inboard discharge valve MO-2-14-012A and 'A' residual heat removal (RHR) inboard discharge isolation valve MO-2-10-025A. In the first valve, the key dislodged from the keyway allowing the motor pinion gear to " free wheel * on the shaft thereby disabling the valve. In the latter case, the key sheared and tore from the keyway binding the pinion gear to the motor shaft. In addition, one of two lugs on the worm shaft clutch of the RHR valve sheared of PECO determined that the installed clutch was the incorrect style. Prior to 1988, a "hard" clutch had been installed rather than the required " soft" style clutch. Both valves were determined to have been operable during the previous operating cycle based on successful valve strokes performed during the following refueling outag l
Motor pinion gear key failures have been documented in prior industry and NRC {
information Notices dating back to the 1980s and have previously occurred at Peach Bottom as well. PEP 10009013 identified 25 previous motor pinion gear-related fasres on 14 valves. In response to earlier failures and industry recommendations, PECO previously had: (1) performed periodic MOV inspections for indications of pending or l existing pinion gear key and keyway failures, (2) upgraded the installed keys to a l
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stronger material (AISI 4140) as recommended by Limitorque, and (3) incorporated the instructions provided in Limitorque Maintenance Update 89-0 The MOV program manager initiated an aggressive MOV inspection effort that takes into consideration the risk importance of each valve and susceptibility to this failure mod Since the discovery of the two failures, nine additional MOVs were inspected and no failures were found. However, the inspection of valve MO-2-10-025B disclosed that the pinion gear had a small amount of play indicating signs of key / keyway wear. PECO replaced the motor assembly to correct the conditio PECO has established internal commitments to inspect a minimum of twenty five valves for signs of motor pinion key and keyway failure prior to completion of the 1999 Unit 3 refueling outage. In addition to the motor pinion gear key inspections, inspection efforts for motor shaft cracking (with increased emphasis on keyway cracking) and worm shaft clutch inspection / verification also were planned. Upon completion, the information gamered from these inspections and earlier PF" s was to be assessed to determine if additional actions were required to control MOV gear problems. The inspectors found PECO's actions to address motor pinion gear key and keyway problems to be acceptabl PECO's evaluation of the sheared lug on the clutch of valve MO-2-10-25A concluded that the lug failed due to stress cracks that had originated from the localized heat treatment process performed by the manufacturer. The second lug was found to have no flaw indications and inspection of additional clutches did not identify any further deficiencies. PEP 10009080 identified that the clutch assembly had been in service for greater than ten years and that the localized heat treatment of clutch lugs had been discontinued by the vendo Irista!Iation of the incorrect style clutch was attributed to human factors, interchangeability of the two clutch styles, lack of specificity in the actuator bill of materials (BOM), and the absence of procedural barriers. Thirty-three MOVs were identified as potentially having a hard clutch installed where a soft clutch is require Inspection of seven MOVs for Unit 2 and one valve for Unit 3 found that all had the specified soft clutch installed. Ten additional MOVs were scheduled for inspection prior to completion of the 1999 Unit 3 refueling outage. The inspectors discussed outstanding evaluations addressing the contributing causes for the error with the MOV program manager. The proposed actions appeared to be adequate to prevent recurrenc Limitoraue Maintenance Update 89-01
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The inspectors reviewed maintenance procedures M-511-120, " Motor inspection / Replacement for Limitorque Motor Operators Size SMB-000 Through SMB-5" and M-C-700-244, "Limitorque Motor Operator Size SMB-0 through SMB-4, including i SB-2 through SB-4 Rebuild and Lubrication." Both documents contained adequate instructions to assure that proper motor pinion gear key material (ANSI 4140) was installed. The instructions contained in Limitorque update 89-01 for securing the motor pinion gear key into the keyway also were incorporated adequatel ;
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f Conclusions PECO's actions to address failures of MOV motor pinion gear keys and keyways and failure of a worm shaft clutch lug in a low pressure coolant injection valve were reasonable and adequate. Corrective actions in response to discovering that the wrong style clutch was installed in the valve also were acceptabl E3_ Engineering Procedures and Documentation E3.1 HPCI System Gland Seal Condenser Leak (Unit 21 and (Closed) LER 2-99-001 Insoection Scope (37551. 71707)
l The inspectors reviewed an event in which the Unit 2 HPCI system gland seal condenser lower head gasket developed a significant leak, prompting operators to declare the
! system inoperable. The inspectors observed engineering and maintenance l
! troubleshooting activities, reviewed the engineering investigation, and discussed the event with several engineering personnel.
l I Observations and Findinas On January 19,1999, while performing quarterly HPCI surveillance testing, equipment
- operators observed an abnormal starting transient. They reported that as the turbine l stop valve was opening, they heatd a loud noise and then observed some vibrating steam lines and a leak (approximately 10-20 gpm) at the gland seal condenser bottom l head gasket. Control room operators immediately shut down the turbine and declared the system inoperabl Engineering and maintenance personnel conducted troubleshooting of several HPCI l i
- system components, including the turbine control system, turbine stop valve, lube oil ( system, pump discharge piping, and stop valve limit switches. The troubleshooting and PECO investigation revealed three significant issues associated with the stop valve lower limit switch, which provides a critical signal to initiate the ramp generator in the turbine control system:
The lower limit switch arm was improperly adjusted during maintenance activities in refueling outage 2R12 (October 1998). Engineering personnelidentified that the maintenance procedure used by the technicians, M-C-756-004, "HPCI Turbine Stop Valve Maintenance" Revision 1, provided no guidance on limit l switch adjustment or post-maintenance testin l l
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An incorrect limit switch, with had a longer dead band than the original, was installed in 1990, which delayed the start of the turbine ramp generato Engineers had noted this difference in 1995, but they did not recognize that the dead band was a critical characteristic, and they did not generate a non-conformance report nor initiate any other action l
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Maintenance and engineering personnel demonstrated a lack of knowledge of the significance of the lower limit switch functions. This led to the design and maintenance deficiencie Engineering personnel concluded that both the improper adji stment and the incorrect
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switch combined to cause a late actuation of the ramp generator. This led to a rapid l speed increase on the turbine, a pressure spike on the water side of the system, and the resulting failure of the gland seal condenser gasket. Operators indicated that they had
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observed abnormalities (" rough starts") during some previous Unit 2 HPCI surveillance j starts, but they did not consider them significant and thus were not documented.
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PECO also identified that an incorrect limit switch was installed on the Unit 3 HPCI l system. This limit switch was replaced during a planned system outage in early February 1999. No significant problems v.ere observed during recent Unit 3 surveillance testing on Unit 3.
i PECO engineers determined ts.; ;he failure of the gasket would not have prevented the HPCI system from performing its intended function. Calculations indicated that the leak !
and room flooding would not have affected other critical components during a design basis six-hour run. However, station management concluded that operators took i appropriate actions to declare the system inoperable, based on the magnitude of the (
leak and the other unexplained conditions at the time of the even I l The inspectors concluded that, overall, engineering troubleshooting and investigation l efforts were good. Engineers appropriately identified the primary causes of this even Planned and completed corrective actions were comprehensive. The inspectors performcd an on-site review of LER 2-99-001, and identified no additional concem Peach Bottom Unit 2 Technical Specification 5.4.1 requires that written procedures be i established, implemented and maintained for the activities listed in Regulatory Guide 1.33, which includes maintenance activities that can affect the performance of safety j related equipment. Maintenance procedure M-C-756-004, "HPCI Turbine Stop Valve l Maintenance," Revision 1, did not provide direction for adjustment of the stop valve lower
! limit switch. Misadjustment of the limit switch led to an abnormal starting transient and a l gland seat condenser leak, prompting operators to declare the HPCI system inoperable.
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This Severity Level IV violation is being treated as a Non-Cited Violation consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as PEP 10009358. (NCV 50-277/99-01-01)
c. Conclusions I l
l A significant leak on the Unit 2 high pressure coolant injection (HPCI) system gland seal ;
condenser was caused, in part, by an inadequate maintenance procedure. This Severity l Level IV violation is being treated as a Non-Cited Violation consistent with Appendix C of i the NRC Enforcement Policy. This violation is in the licensee's corrective action program as PEP 1000935 . .
l 21 I
Engineering troubleshooting and investigation efforts following the significant leak on the l Unit 2 high pressure coolant injection system gland seal condenser resulted in effective corrective actions. However, cperations and engineering hadmissed opportunities, prior ( to the leak, to identify the cause of the abnormal high pressure coolant injection system respons E4 Engineering Staff Knowledge and Performance E4.1 Emilgre of Unit 2 Reactor Buildino Damoer in the Standby Gas Treatment System to Automatically Open on Demand Insoection Scope (37551)
On January 21,1999, the station made a four hour non-emergency 10 CFR 50.72 report to the NRC when a damper in the flow path from the Unit 2 reactor building ventilation to the standby gas treatment system (SGTS), failed to open. The inspectors reviewed ,
applicable doc Jmentation and system drawings and discusseo the issue with site {
engineering personnel, Observations and Findinas At the time of the 10 CFR 50.72 report, station personnel believed that the failure could have prevented the SGTS from fulfilling its safety function. The SGTS is used to control the release of radioactive material during an event. Subsequently, site engineering personnel determined that even witn the damper failure, there was adequate flow from )
the Unit 2 reactor building to the SGTS through the refuel floor hatch and the refueling floor ventilation. Based on this information, the licensee retracted the 10 CFR 50.72 repor During the review of this issue, the inspectors questioned site engineering if the refuel floor hatch plug, for either unit, was ever installed and whether the reactor building ventilation to the SGTS was vulnerable to single failure if the plug was installed. These questions were raised because in both units there is only one ventilation flow path from each reactor building to the SGTS for that unit. Site engineering personnel discovered that on March 5,1998, the refuel floor hatch plug was installed for approximately seven and a half hours on Unit 3. During this time, no problems were noted with any dampers in the ventilation path or ventilation system from the Unit 3 reactor building to the SGT l Therefore, the SGTS had remained operable during this time. However, sits engineering personnel determined that with the refuel floor hatch plug installed and a single failure of a damper in the ventilation from the reactor building to the SGTS, the SGTS would be inoperable and unable to perform its design function. Although the inspectors were l concemed that station personnel did not fully recognize the impact of installing the refuel floor hatch plug on the operability of the SGTS, the inspectors had no concems with the analysis and conclusions reached by site engineering. The inspectors determined that initial reporting of this issue per 10CFR 50.72 showed good conservative action by <
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station personnel and analysis performed for concluding that the SGTS was operable when the damper failed was acceptable l
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i 22 Conclusions l On January 21,1999, the station made a four hour non-emergency 10 CFR 50.72 report to the NRC when a damper in the flow path from the linit 2 reactor building ventilation to the standby gas treatment system failed to open. Subsequently, the station retracted this 10 CFR 50.72 after additional engineering analysis. Initial reporting of this issue per 10CFR 50.72 showed good conservative action by station personnel and analysis performed for retracting the 10 r~ 'O.72 and concluding that the standby gas treatment system was operable'. cceptabl E4.2 Understandino of the 3D-MONICORE Computer Proaram by Reactor Enaineerina Insoection Scope (37551)
The inspectors reviewed reactor engineering training and qualification for use of the 3D- j MONICORE computer progra _ Observations and Findinas l The licensee has incorporated administrative limits into station procedures based on the i inherent limitations in the predictive capabilities of the 3D-MONICORE progra I Recognition of the limitation and the inherent accuracy of the 3D-MONICORE program )
and previous performance challenges was planned as a reactor engineer continuing !
training topic during the Spring 1999 training schedul The inspectors reviewed selected lesson plans and course materials for the reactor engineering 3D-MONICORE computer program training and qualification matrix. The inspectors compared the list of qualified reactor engineers with the matrix and verified 1 that all qualified engineers had taken required 3D-MONICORE training. The inspectors discussed the reacto, engineering training program with the instructors and the reactor engineering manager. The inspectors determined that initial qualification and continuing cycle training for reactor engineers provided sufficient knowledge to effectively monitor and maintain the reactor core and plant parameters within required limit Conclusions The training program and qualifications of the reactor engineering personnelwas adequate for effective operation and use of the 3D-MONICORE computer progra o e 4
E8 Miscellaneous Engineering issues
- E (Closed) Insoector Follonuo item (IFI) 50-277(2781/97-02-07 Review of Desian Basis Document Review and Acoroval Process 1 NRC Inspection Report 50-277(278)/97-02 documented an observation that several design basis documents (DBDs) were missing some review signatures. Inspector
' Follow-up Item (IFI) 97-02-07 was opened, pending location of original review documentation or completion of the review proces Engineering personnel examined all DBDs and the archived original approval '
documentation for selected DBDs. They determined that the final reviews and approvals of the DBDs were properly performed and documented by the designated design authority representatives. The missing signature blocks were due to minor
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administrative oversights role x1 to the filing of the signature pages and the markings 'or the signature blocks. The inspectors noted that corrective actions were taken for the administrative oversight The inspectors discussed this issue with an engineering manager and reviewed a sample of DBDs. No concems were identified with the review and approval documentation. The inspectors have no additional concerns with this issu ,
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i E8.2 (Closed) LER 50-277/2-98-006 Unit 2 Reactor Water Cleanuo (RWCU) Isolated on Hiah l System Flow Durina System Restoration i
l This event was discussed in NRC Inspection Raport 50-277(278)/98-11, Section E2.1, l The inspectors performed an on-site review oD.he LER. No new issues were revealed
! during this revie E8.3 (Closed) Unresolved item (URI) 50-277(278)/97-06-02 Incorrect Seismic Response Soectrum Used to Perform Recirculation System Pioina Anajy.agg l
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During an engineering design review around August 18,1997, PECO engineering became aware of an incorrect seismic response spectrum used to perform seismic analyses in 1983 of loop 'A' of the recirculation system piping on Unit 2. PECO initially analyzed the piping using the method and damping factors given in the UFSAR. This analysis identified that some of the piping stress values were above the ASME code allowabie values. PECO reanalyzed this piping using ASME Code Case N411 which allowed increased damping factors above those stated in the UFSAR. The reanalysis showed that piping stress values were within ASME code allcwable values and therefore the piping was operable. The inspectors questioned the use of ASME Code Case N411 in lieu of the UFSAR described method and damping factors. The inspectors also questioned the operability of the piping and that PECO did not report this issue to the NR The inspectors forwarded the questions noted above to Nuclear Reactor Regulation ]'
(NRR) for review. After obtaining information from PECO regarding these questions, t
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NRR concluded that use of ASME Code Case N411 and development of the floor response spectra used for the stress analysis of this recirculation system piping was acceptable. Based of the conclusion by NRR, the piping was operable and therefore the condition was not required to be reported to the NRC. The inspectors have no additional concems with this issu IV. Plant SUDDOrt l RZ Status of RP&C Facilities and Equipment R2.1 Calibration of Effluent, Process Radiation Monitorina Systems (RMS). Calibration of Flow Rate Measurino Devices. and Calibration of Hydroaen Monitors i Inspection Scope (84750)
The inspectors reviewed: (1) the most recent calibration results for the following selected effluent / process / area RMS and its system flow rates; (2) RMS df assessment; and (3) review of the RMS Improvement Pla Radiation Monitorina Systems
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Liquid Radwaste Effluent Monitor (common)
. Service Water Effluent Monitors
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Reactor Building Closed Component Cooling Monitors
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Main Stack Noble Gas Monitors (common, normal and wide range)
Roof Vent Noble Gas Monitors ,
. Emergency Service Water Effluent Monitor I
. Offgas Monitors l
. Control Room Ventilation Monitor l
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. Refueling Floor Vent Exhaust Monitor
. Drywell High Range Monitors l Calibration of Flow Rate Measurina Devices
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Liquid Radwaste Effluent Line Flow Rate Measuring Device
. Main Stack Flow Rate Measuring Device I Observations and Findinas Electronic alignment results for the above RMS and flow rate indicators were found to be l
within the licensee's acceptance criteria. Electronic alignment testing was improved for ,
Sorrento monitors. Radiological calibration methodology for the above RMS was ;
acceptable. Linearity tests were appropriate. Operating high voltage was properly set by determining the optimum high voltage set point. Secondary calibrations validated primary calibrations. Tracking and trending efforts were also goo .
., a 25 Conclusions The licensee established, implemented, and maintained an effective program with respect to electronic calibrations, radiological calibrations, system reliability, and tracking and trendin R2.2 Air Cleanina Svstams (84750)
The inspection consisteo of the licensee's most recent surveillance test results (visual inspection, in-place high efficiency articulate air (HEPA) and charcoal leak tests, air capacity tests, pressure drop tests, and laboratory tests for lodine collection efficiency for the following ventilation systems: i
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. Standby Gas Treatment
. Recombiner
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Turbine Building Deficiencies identified during surveillance testing for the atiove systems were corrected and as left conditions met the licensee's acceptance criteria. In summary, the . licensee l established, implemented, and maintained an effective ventilation system surveillance j program with respect to charcoal adsorption surveillance tests, HEPA mechanical 1 efficiency tests, and air flow rate test R4 Staff Knowledge and Performance in RP&C R Removal of Contaminated Filters from the Unit 3 Soent Fuel Pool Insoection Scope (71750)
The inspectors observed the activities on the Unit 3 refuel floor during the removal of contaminated filters from the spent fuel poo Observations and Findinas While transferring a contaminated filter from the spent fuel pool to a shipping cask on January 12,1998, an area radiation monitor (ARM) alarmed at 20 millirem per hou Personnel working in the area moved to lower dose areas with the exception of the radiation technician and the overhead crane operator on the bridge. The radiation technician was monitoring radiation levels and informed the operator that levels had not significantly changed. The ARM was set at 20 millirem /hr and the radiation technician verified this reading with his instrumentation. The alarm cleared as the operator raised the filter into the transfer bell and transfer of the filter to the shipping cast was complete The inspectors reviewed the procedure, M-020-004, "CNS-8-1208 Transport Cask Handling," and noted that the procedure specified a maximum distance of two inches from the bottom of the shielded transfer bell to the top of the water while transferring the
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filters into the bell. The inspectors observed that the shielded transfer bell appeared to be greater than the two inches from the water. Maintenance personnel measured the distance and found that it was approximately five inches from the water. The shielded bell was lowered to approximately two inches from the water. No additional ARM alarms occurred during the remainder of the filter moves. Later that day, maintenance personnel licensee secured a marker to the shielded transfer bell that indicated when the l bell was approximately 2 inches from the water.
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Generally, the inspectors observed that movement of the contaminated filters was performed well with good radiation technician monitoring and oversight. The workers l exhibited good ALARA awareness and actions. However, the inspectors noted that site management expectations were that when an unexplained condition is encountered,
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work should be stopped until the cause of the condition is identified and corrected. The l inspectors determined that personnel performing this job did not adequately identify and correct the cause of the ARM alarm until questioned by the inspectors. The inspectors I also noted that this was an example of a weakness in fully following the work procedure.
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c.- Conclusions l Generally, movement of the contaminated filters from the spent fuel pool to the shipping
cask was performed well with good radiation technician monitoring and oversight and
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good ALARA awareness and actions by the workers. The inspector observed a slow l response to an area radiation monitor alar R7 Quality Assurance (QA)in RP&C Activities Insoection Scooe (84750)
l The inspection consisted of (1) a review of the 1998 QA audit and discussion of 1998 l audit responses with chemistry staff, (2) a review of QA surveillances; (3) a review self-l assessments; (4) a review of inter-laboratory measurement comparisons; (5) a review of the chemistry laboratory quality control program for radioactive liquid and gaseous effluent samples; and (6) a review of Performance Enhancement Program (PEP) report Observations and Findinos The 1998 QA audit covered most aspects of the radioactive effluents control progra QA surveillances and self-assessments helped provide a more performance-based review of the radioactive effluerts control program. Responses to audit findings were reasonable. No new discrepancies of regulatory significance were identifie Discrepancies pertaining to inter-laboratory comparative tests were investigated and
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resolved. Laboratory QC data results indicated that the licensee implemented very good I
quality control of chemistry laboratory counting equipmen s. .
c.- Conclusions The licensee established, implemented, and maintained an effective program with respect to response to audit findings and quality control for validating measurement results for radioactive effluent sample R Miscellaneous RP&C lasues R Offsite Dose Control Manual (ODCM) Revision 11 (84750)
The inspectors reviewed several ODCM changes with a staff chemist. Most of the changes were minor in nature and none negatively impacted the quality of the radioactive effluents control program. No inadequacies in the ODCM were note R8.2 Noble Metals Addition (84750)
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The licensee started a noble metalinjection program at the start of the current Unit 2 operating cycle. In conjunction with noble metals addition, the licensee has reduced the hydrogen rates (the purpose of noble metals addition was to promote a high degree of protection against inter-granular stress corrosion cracking at lower hydrogen injection rates). As a result, the main steam line dose rate increase attributable to hydrogen injection was lower than had been the case prior to noble metals additio S1 Conduct of Security and Safeguards Activities Inspection Scope (81700)
Determine whether the conduct of security and safeguards activities met the licensee's commitments in the NRC-approved security plan (the Plan) and NRC regulatory requirements. Areas inspected included: access authorization program; alarm stations; communications; and protected area access control of personnel and packages, Observations and Findinas Access Authorization Proaram.
l The Access Authorization (AA) program was reviewed to verify implementation was in
, accordance with applicable regulatory requirements and Plan commitments. The review
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included an evaluation of the effectiveness of the AA procedures, as implemented, and an examination of AA records for 15 individuals. Records reviewed included both persons who had been granted and had been denied access. The AA program, as implemented, provided assurance that persons granted unescorted access did not ;
constitute an unreasonable risk to the health and safety of the public. Additionally, j access denial records and applicable procedures were reviewed to verify that appropriate actions were taken when individuals were denied access or had their access terminate fm
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Operations of the Central Alarm Station (CAS) and the Secondary Alarm Station (SAS)
were reviewed and determined to be equipped with appropriate alarms, surveillance and communications capabilities. Interviews with the alarm station operators found them knowledgeable of their duties and responsibilities. Observations and interviews also verified tt;at the alarm stations were continuously manned, independent and diverse so that no single act could remove the plant's capability for detecting a threat and calling for assistance and the alarm stations did not contain any operational activities that could interfere with the execution of the detection, assessment and response function Communication Document reviews and discussions with alarm station operators determined that the alarm stations were capable of maintaining continuous intercommunications, continuous communications with each security force member (SFM) on duty, and alarm station operators were testing communication capabilities with the local law enforcement agencies as committed to in the Pla Protected Area (PA) Access Control of Personnel and Hand-Carried Packaae On January 12 and 13,1999, during peak activity periods, personnel and package search activities were observed at the personnel access portal. Positive controls were determir.ad to be in place to ensure only authorized individuals were granted access to the PA and that all personnel and hand-carried items entering the PA were properly searche c. Conclusigrig The licensee was conducting its security and safeguards activities in a manry t at i protected public health and safety in the areas of alarm stations, communici' ions and i protected area access control of personnel and packages. This portion of the program, as implemented, met the licensee's commitments and NRC requirement Status of Security Facilities and Equipment a. Insoection Scope (81700)
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Areas insperf.ed were: PA assessment aids; PA detection aids and personnel search equipment i b. Observafwns_and Findinas l Assessment Aid On January 13,1999, the effectiveness of the assessment aids was evaluated by ,
observing on closed circuit television (CCTV), a SFM conducting a walkdown of the P l
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, The assessment aids had good picture quality and excellent zone overlap. Additionally, l to ensure Plan commitments are sat >"ed, the licensee has procedures in place requiring
! the implementation of compensatory :..easures in the event the alarm station operator is l unable to properly assess the cause of an alarm. On January 14,1999, inclement l'
weather rendered several CCTV cameras ineffective for assessment of alarms and the licensee was observed implementing compensatory measures; performing corrective maintenance and conducting return to service testing. All actions implemented were l l appropriat i
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PA Detection Aid On January 13,1999, testing was observed of selected intrusion detection zones in the plant protected area. Through observations and review of the testing documentation associated with the equipment repairs, it was verified that repairs were made in a timely )
manner and that the equipment was functional and effective, and met the commitments
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in the Pla Personnel and r)acF;p Search Eauipmen On January 14,1999, both the rowne use and the weekly performance testing of the licensee's personnel and package search equipment were observed. Personnel search - i equipment was being tested and maintained in accordance with licensee procedures and !
the Plan and personnel and packages were being properly searched prior to PA acces !
Observctions and procedural reviews cieterrained that the search equipment performed b recordance with licensee procedurcs and Plan commitment c. Conclusions The licensee's security facilities and equipment were determined to be well maintained and reliable and were able to meet the licensee's commitments and NRC requirement l S3 Security and Safeguards Procedures and Documentation l a. Inspection Scooe (81700)
Areas inspected were: implementing procedures and security event log b. Observations and Findinas Security and Proaram Procedures.
l Review of selected security program implementing procedures verifief that the >
l procedures were consistent with the Plan commitments with one exception. Standard operating procedure " Response to Contingency Eyents and Security Related Threats,"
NSS/ SOP-2, identiiled the defensive positions that were manned during Contingency Events and the Plan identified the minimum number of armed responders available
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onsite at all times. The review disclosed a discrepancy between the number of defensive positions and the minimum number of armed responders identified in the Pla Review of manning rosters determined that appropriate numbers of armed responders were onsite at all times to man all defensive positions. However, the licensee stated that the Plan would be revised in accordance with the provisions of 10 CFR 50.54(p) before the end of the first quarter of 1999 to reflect the appropriate minimum number of armed responder Security Event Loa The Security Event Logs for the previous nine months were reviewed. Based on this l review. and discussion with security management, it was determined that the licensee i appropriately analyzed, tracked, resolved and documented safeguards events that the '
licensee determined did not require a report to the NRC within 1 hou c. Conclusions Security and safeguards procedures and documentation were being properly implomented. Event Logs were being properly maintained and effectively used to analyze, track, and resolve safeguards events. A revision to the Plan will resolve a discrepancy between the implementing procedure and the Plan relative to the minimum number of armed responder S4 Security and Safeguards Otaff Knowledge and Performance a. Insoection Scope (61700)
Area inspected was security staff requisite knowledg b. Observations and Findinas Security Force Reauisite Knowledo A number of SFMs in the performance of their routine duties were observed. These observations included alarm station operations, personnel and package searches, and exterior patrol alarm response. Additionally, SFMs Nere interviewed and based on the responses to questioning, it was determined that the SFMs were knowledgeable of their responsibilities and duties, and could effectively carry out their assignment i
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c. Conclusions The SFMs adequately demonstrated that they had the requisite knowledge necessary to effectively implement the duties and responsibilities associated with their positio .
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85 Security and Safeguards Staff Training and Qualifications (T&Q)
a. Inspection Scope (81700)
l l Areas inspected were security training and qualifications and training records.
l 3 b. Observations and Finding Security Trainina and Qualification On January 12,1999, T&Q records of 8 SFMs were reviewed. The results of the review indicated that the security force was being trained in accordance with the approved T&Q ,
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Trainina Record Through review of training records, it was determined that the records were properly maintained, accurate and reflected the current qualifications of the SFM '
c. Conclusions Security force personnel were being trained in accordance with the requirements of the ;
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T&Q Plan. Training documentation was properly maintained and accurate and the training provided by the training staff was effectiv S6 Security Organization and Administration a. Inspection Scope (81700) l Areas inspected were management support and staffing level b. Observations and Findinas Manaaement Suppor Review of various program enhancements made since the last program inspection included upgrades to the alarm assessment system enhancements to guardhouse security and upgrades to the security communications syste Staffina Level The total number of trained SFMs immediately available on shift met the requirements specified in the Plan and implementing procedures.
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c. Conclusion The level of management support was adequate to ensure effective Imr,lementation of the security program, and was evidenced by the allocation of resources to support programmatic need V. Manaaement Meetinas X1 Exit Meeting Summary The insr, actors presented the results of the inspection to members of licensee management on February 21,1999. The licensee acknowledged the findings presente No proprietary information was identified by the license ~
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i Attachment 1 33
ATTACHMENT 1
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i INSPECTION PROCEDURES USED l l
IP 37551 Onsite Engineering Observations IP 61726 Surveillance Observations
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IP 62707 - Maintenance Observations-IP 71707 Plant Operations IP 71750 - Plant Support Observations IP 81700 - Physical Security Program for Power Reactors
. IP 8475 Radioactive Waste Treatment, and Effluent and Environmental Monitoring IP 90700 Feedback of Operational Experience Information at Operating Power Reactors IP 92903 Followup - Engineering ITEMS OPENED, CLOSED, AND DISCUSSED Ooened/ Closed 50-277/99-01-01 NCV Inadequate Maintenance Procedure Results in High Pressure Coolant injection System Gland Seal Condenser Leak i Closed 50-278/3-98-005 LER inadvertent Unit 3 Electrical Bus E33 Trip During Performance of Unit 2 Electrical Bus E32 Surveillance Test
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50-277/2-98-006 LER Unit 2 Reactor Water Cleanup (RWCU) Isolated on High System Flow During System Restoration 50-277/2-98-009 LER Unplanned Engineered Safety Feature Actuations Resulting from a Transformer Insulator Failure 50-277/98-01-01 VIO Inadequate Verification of Alarm Acknowledgment due to Control Room Supervisor leaving Work Station Without Relief 50-278/98-01-01 VIO Inadequate Verification of Alarm Acknowledgment due to Control Room Supervisor leaving Work Station Without Relief 50-277/98-01-02 VIO Missed Technical Specification Surveillance Requirement Test for Verification of Proper flow in the Recirculation Loops 50-277/98-01-03 VIO Missed Technical Specification Surveillance Requirement Test for Verification of Core Flow as a Function of Thermal Power 50-277/98-01-05 VIO Unexpected T: .sf Unit 2 Main Turbine During Start-up
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l-Attachment 1 34 50-278/98-01-06 VIO Unit 3 Exceeded Licensed Power Level Due to inaccurately Calibrated Feedwater Temperature Instruments 50-277/97-02-07 IFl Review of Design Basis Document Review and Approval Process 50-278/97-02-07 IFl Review of Design Basis Document Review and Approval Process 50-277/97-06-02 URI Incorrect Seismic Response Spectrum Used to Perform
, Recirculation System Piping Analyses l- 50-278/97-06-02 URI Incorrect Seismic Response Spectrum Used to Perform l Recirculation System Piping Analyses
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50-277/2-99-001 LER High Pressure Coolant injection System Failure Due to Gland Seal l Condenser Leak I
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Attachment 1 L LIST OF ACRONYMS'UCEO AA access authorization l -AF application factor l ARM area radiation monitor-ARC alarm response card BOM bill of materials CAS Central Alarm Station CCTV' closed circuit television CDF core damage frequency CECO Commonwealth Edicon Company CM corrective maintenance CS core spray
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DBDs design basis document i ECCS emergency core cooling system ESCAPE Equipment Status Control Action Plan ESF engineered safety feature FCR field change request GL generic letter HEPA -high efficiency particulate HPCI high pressure coolant injection IMIS in-process maintenance improvement system IPE individual plant evaluation IFl inspection follow-up system .
l I&C instrumentation and controls LPCI low pressure coolant injection LER licensee event report LERF large early release frequency LPCI low pressure coolant injection MOV motor-operated value NCR(s) nonconformance reports (s)
NON-EQ non-environmentally qualified NOTICE notice of violation NRB Nuclear Roview Board ODCM Offsite Dose Calculation Manual OT operational transient i PA protected area I PBAPS Peach Bottom Atomic Power Station PDR public document room PECO Peco Energy PECON Peco Nuclear PEP performance enhancement program the Plan NRC-approved physical security plan PIRLs PEP issue Review Leaders ;
PMT post-maintenance testing PRA probabilistic risk assessment QA quality assurance I
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j Attachment .1 2 QC quality control l
RMS radiation monitoring system j l RPge: radiological protection and chemistry )
RHR rer.idual heat removal RCIC reactor core isolation RMS radiation monitoring system RWCU reactor water cleanup SAS secondary alarm station SFM security force member ST surveillance test T&Q training and qualification TS technical specification i TSA- technical specification action i TU technical update UFSAR ~ updated final safety analysis report URI unresolved item l
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