IR 05000334/1999001
| ML20206B295 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 04/22/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20206B280 | List: |
| References | |
| 50-334-99-01, 50-334-99-1, 50-412-99-01, 50-412-99-1, NUDOCS 9904290205 | |
| Download: ML20206B295 (72) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
i Licer,se Nos.
50-334/99-01,50-412/99-01 l
Docket Nos.
50-334,50-412 Licensee:
Duquesne Light Company Post Office Box 4 Shippingport, PA 15077 Facility:
Beaver Valley Power Station, Units 1 and 2 Inspection Period:
February 7,1999 through March 20,1999 Inspectors:
D. Kem, Senior Resident inspector G. Dentel, Resident inspector G. Wertz, Resident inspector G. Smith, Security Specialist A. Lohmeier, Senior Reactor Engineer Approved by:
Wayne L. Schmidt, Acting Chief
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Projects Branch 7
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9904290205 990422 PDR ADOCK 05000334 G
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EXECUTIVE SUMMARY Beaver Valley Power Station, Units 1 & 2 NRC inspection Report 50-334/99-01 & 50-412/99-01 This integrated inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a 6-week period of resident inspection. In addition, it includes the results of announced inspections by regional security and inservice inspection specialists.
The Duquesne Light Company operated Beaver Valley Unit 1 (Unit 1) and conducted normal operations and shutdown activities at Beaver Valley Unit 2 (Unit 2) safely over the inspection.
period.
Operations Refueling activities including the reacter cavity draindown were generally conducted well.
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Preevolution briefings, procedure adherence, and supervisor oversight were good.
. Technical specification (TS) surveillance requirements were met and were well controlled. Refueling personnel and Quality Services Unit personnel provided critical self-identification of problems and captured them into the corrective action program.
Management oversight was evident in support of the activities. (Section O1.2)
Human performance was generally good. Station personnel maintained a low tolerance
threshold by identifying numerous minor human performance deficiencies at the beginning of the Unit 2 refueling outage. Management aggressively responded to these problems with a plant-wide work stoppage to review the problems, improve preevolution briefing standards, and reenforce self-checking techniques. Increased senior plant management observations of proevolution briefings added emphasis to self-checking techniques. These timely actions help to prevent more significant human performance errors. (Section 01.3)
Outage configuration control improved, based'on implementation of the computer-based
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clearance system in May 1998, combined with additional clearance reviews by senior reactor operators and reactor operators. The clearances associated with the service water system and a residual heat removal valve were properly written and completed.
(Section O2.1)
Operators maintained comprehensive and accurate logs that clearly identified significant
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activities and applicable TS limiting conditions of operation. Plant problems described in the logs, were effectively transferred into the corrective action system for resolution.
(Section O3.1)
The Independent Safety Eva!uation Group (ISEG) pre-outage safety review verificci that
the Unit 2 outage schedule provided sufficient safety margin. The ISEG provided a comprchensive ongoing review of work scope and schedule changes and real time
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assessment of plant risk throughout the refueling outage. Station persormel maintained i
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an awareness of key safety parameters during the outage through effectively
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communication of shutdown safety status sheet information on a shiftly basis. (Section
07.1).
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An inadequate calibration procedure, due to unclear vendor technical information and a e'
lack of understanding by the system engineer, resulted in plant operation with one of the
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two required source range nuclear instruments inoperable. The root cause and corrective actions were appropriate to preclude repetition. This Severity Level IV violation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy and is addressed in the corrective action program as CR
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g82035. (NCV 50-412/99-01-01) (Section 08.2)
The corrective action program did not fully evaluate or resolve several recent deficient
conditions, including compensatory actions associated with emergency bus degraded voltage instrumentation and TS LCO action and surveillance requirements. The inspectors determined that common factors included department manager acceptance of
incomplete condition raport investigations, insensitivity to TS requirements, and hesitancy to initiate condition reports. Following discussions with inspectors, senior
. management established a team to evaluate the corrective action deficiencies and
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determine whether underlying weaknesses exist. (Section O8.3)
J Maintenance
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The nine observed planned maintenance activities, including station battery replacement,
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auxiliary feedwater pump inspection, and residual heat system valve repair, were
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L performed safely and in accordance with maintenance work instructions. The work i
packages, including post-maintenance testing requirements, were good. System
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engineers actively supported the work activities where appropriate. Maintenance supervisors demonstrated good job ownership and leadership in the field. (Section M1.1)
The seven observed surveillance tests were performed safely and in accordance with
proper procedures. Management placed more emphasis on preevolution briefings for infrequently performed evolutions following several minor human performance deficiencies observed early in the refueling outage. The assignment of test directors, the quality of preevolution briefings, and test implementation for safety injection full flow tests were excellent. (Section M1.2)
The preventive maintenance program effectively maintained and performance testing
monitored the safety related heat exchangers. System engineers conducted comprehensive performance monitoring and assessment. (Section M2.1)
Engineenna Two Unit 2 design changes were properly implemented to correct risk significant
. deficiencies which had necessitated longstanding operator workarounds. The service u
water pump seal supply modification was well written including a detailed safety l
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evaluation and comprehensive installation test plan. Engineers demonstrated thorough knowledge of the design change and closely monitored Leth installation and testing.
Foreign material exclusion controls, configuration controls, and communications were appropriate during design change installation and testing. (Section E1.1)
Pionning and implementation of the second 10 year interval, first period, inspection,
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including comprehensive steam generator inspections, was consistent with American
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Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (B&PVC)
Section XI requirements. (Sections E1.2 and E1.4)
Unit 2 refueling outage number 7 non-destructive examinations were implement 6J in
accordance with ASME B&PVC Section XI and Section lil rules for magnetic particle, ultrasonic, and radiographic examination and were performed by qualified and certified inspectors using acceptable procedures. Stuck reactor vessel head closure studs were properly evaluated. (Sections E1.3 and E1.5)
Plant Support
- Security force members were property trained, security equipment was properly
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maintained, and security and safeguards activities were effectively conducted in a
. manner that protected public health and safety in the areas of access authorization,
> alarm stations, communications, and protected area access control of personnel and packages. Management support was adequate to ensure effective implementation of the security program, and was evidenced by adequate staffing levels and allocations of resources to support programmatic needs (Sections S1-S6)
The Fitness-for-Duty and Secunty Program audits were comprehensive in scope and
depth, audit findings were reported to the appropriate level of management, and the audit program was being properly administered. In addition, a review of the documentation applicable to the self-assessment program indicated that the program was being effectively implemented to identify and resolve potential weaknesses.
(Section S7)
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TABLE OF CONTENTS Page
. EXEC UTIVE SUM MARY......................................................... i TABLE OF CONTENTS........................................................ iv 1. Operations............................................................... 1 O1 Conduct of 0perations............................................ 1 01.1 General Comments......................................... 1 01.2 Unit 2 Refueling Activities.................................. 1 01.3 Human Performance...................................... 3
Operational Status of Facilities and Equipment......................... 4 02.1 Configuration Control Related to Clearance Activities............. 4
Operations Procedures and Documentation........................... 5 03.1 Operator Logs............................................ 5
Quality Assurance in Operations.................................... 5 07.1, Unit 2 Pre-Outage Safety Review............................. 5
. O8 _ Miscellaneous Operations issues................................... 6 08.1 (Closed) Licensee Event Report 50-412/98-13................... 6 08.2 (Closed) Licensee Event Report 50-412/98-14.................... 7 08.3 Incomplete Condition Report investigations or Corrective Actions..... 8 ll. Maintenance.............................................................. 1 1 M1.
Conduct of Maintenance......................................... 11 M1.1 Routine Maintenance Observations.......................... 11 M1.2 Routins Surveillance Observations........................... 12 M2 Maintenance and Material Condition of Facilities...................... 13 M2.1 Safety Related Heat Exchanger Program Review...............
M8 Miscellaneous Maintenance issues................................. 14 M8.1 (Closed) Licensee Event Report 50-412/98-12..................
I l l. Engineering........................................................... 14
'E1 Conduct of Engineering.......................................... 14 E1.1 Development and implementation of Design Changes............
E1.2 Unit 2 In-Service inspection Program......................... 16 J
E1.3 Reactor Vessel Head " Stuck Studs".......................... 16 E1.4 Unit 2 Steam Generator Inspection........................... 18 E1.5 ISI Observations and Results............................... 19 E8 Miscellaneous Engineering lasues................................. 20 E8.1 (Closed) VIO 50-334(412)/98-01-03........................... 20 IV. Plant Support........................................................... 21 R1 Radiological Protection and Chemistry (RP&C) Controls................ 21 R1.1 Radiological Worker Perfo mance............................ 21 S1 mConduct of Security and Safeguards Activities....................... 21 i
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Status of Security Facilities and Equipment.......................... 22
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S3 Security and Safeguards Procedures and Documentation................ 23
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S4 Security and Safeguards Staff Knowledge and Performance............. 23 SS Security and Safeguards Staff Training and Qualifications (T&Q)........
l S6 Security Organization and Administration............................ 25 S7 Quality Assurance (OA) in Security and Safeguards Activities............. 25
V. Management Meetings................................................... 26 X1 Exit Meeting Summary........................................... 26 X2 Management Meeting Summary.................................. 27 lNSPECTION PROCEDURES USED.......................................... 28
' lTEMS OPENED, CLOSED AND DISCUSSED................................... 29 LIST OF ACRONYM S USED................................................. 30 i
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Report Details
Summary of Plant Status The Duquesne Light Company (DLC) operated Beaver Valley Unit 1 (Unit 1) and conducted normal operations and shutdown activities at Beaver Valley Unit 2 (Unit 2) safely over the
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inspection period.
I Unit 1 began this inspection period at 100 percent power. On February 14, the unit was forced
to shut down due to degrading secondary plant chemistry due to a leak in the "C" main turbine
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condenser. The outage was extended due to problems with the condenser steam dump valves.
The operators restarted the unit on February 24 and synchronized it to the offsite power grid on February 25. The unit experienced problems with the secondary plant steam system which limited power operation to 98 percent for the remainder of the period.
Unit 2 began this inspection period at 100 percent power. On February 26, operators manually shut down the reactor for the seventh refueling outage. On March 7, the unit entered Mode 6
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(refueling when the reactor vessel head was detensioned. The unit remained in Mode 6 through
the end of the period.
1. Operations
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Conduct of Operations
01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations, in general, the conduct of operations was professional and safety-conscious; specific events and noteworthy observations are detailed in the
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01.2 Unit 2 Refueling Activities a.
inspection Scoce (71707)
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The inspectors observed activities associated with defueling, refueling, and reactor coolant system (RCS) draindown. The inspectors interviewed the refueling engineers, refuel senior reactor operators (SRO), vendor personnel, and operations department managers to verify their understanding of applicable technica; specification requirements.
The inspectors reviewed and observed the following refueling procedures:
20ST-49.3
" Refueling Operations Prerequisites," Rev. 4
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2RP-3.11
" Refueling Procedure New Fuel Movement," Rev. 0
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2RP-3.16
" Refueling Procedure Core Unload," Rev. 0
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2RP-3.23
" Refueling Procedure Core Reload," Rev. 0
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20M-6.4.1
. Draining the RCS for Refueling," Rev.11
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Observations and Findinos Generally the plant staff conducted the observed defuel, refuel, and RCS draindown activities well.. The preevolution briefing for the RCS draindown was thorough and
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effectively utilized operating exponence. During the draindown, the inspectors observed good supervisor oversight, minimization of control room activities and distractions, and effective establishment of constant communications with operators in containment.
During the defuel and refuel, the inspectors observed good command and control in containment. Discussions with the refueling engineer indicated a sound knowledge of the technical requirements for the activities. Administrative controls were good and included routine shift briefings and appropriate oversight of vendor activities.
Management oversight was also observed and provided additional support to the activities.
Overall, the procedures provided clear and accurate guidance for the tasks being performed. DLC personnel identified minor procedure implamentation problems and q
properly entered them into the corrective action program. However, the inspectors noted incomplete procedure guidance for performing the RCS draindown, Specifically, the draindown procedure did not identify the need to operate 2CH6-LOV115A which provides letdown flow to the boron recovery system. The inspectors discussed thic with the control room operators who indicated that use of this valve was routine and familw.
However, since the draindown was a non-routine event, the Unit 2 Operations Manager
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Technical specificatior. (TS) surveillance requirements were properly identified in
. refueling procedure 2OST-49.3. Nuclear shift supervisors were cognizant of the requirements and plant status while refueling operations were ongoing. Chemistry, System and Performance Engineering, and Maintenance departments each had appropriate tracking mechanisms in place to support assigned 1.. survei!!ance requirements.
Quality Services Unit (QSU) personnel performed good independent inspections and identified several minor procedure inconsistencies and foreign material exclusion problems that were entered into the corrective action program for resolution. Refueling personnel were also critical in self-identifying and capturing into the corrective action
. program problems encountered with procedure adherence, communications, and equipment performance.
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Conclusions Refueling activities including the reactor cavity draindown were generally conducted well.
- Preevolution briefings, procedure adherence, and supervisor oversight were good. TS surveillance requirements were met and were well controlled. Refueling personnel and-QSU personnel provided a critical self-identification of problems and captured them into u
the corrective action program. Management oversight was evident in support of the activitie d i
1 01.3 Human Performance a.
Insoection Scooe (71707)
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The inspectors reviewed human performance events as they occurred throughout the
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Unit 2 outage, focusing on root cause analysis and effectiveness of corrective actions.
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Observations and Findings Human performance during the period was generally good. Early in the Unit 2 outage, however, over a dozen human performance errors were ncted! None of these errors by
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themselves were safety significant. However, the trend, if left uncorrected, could have led to more significant problems. One error, involving source range nuclear instrument calibration requirements, was reportable as a licensee event report (LER.) Senior management aggressively responded to the human performance problems. The Vice-President of the Nuclear Services Group convened a task force led by the Manager of
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- System and Performance Engineering to review a group of recent condition reports r
(CRs) and to identify the common causal factors. The team concluded that a lack of attention to detail on the part of the individual performer and verifier, and poor procedure equality contributed to the human performance problems. The team recommended
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improvements in the proevolution briefings, increased presence of in-plant supervision, and a renewed emphasis on self-checking.
The Vice-President Nuclear Operations Group and Plant Manager also directed a plant-wide work stoppage on March 4, in order for each organization to review the human performance problems and to reiterate edf-checking techniques. The individual
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meetings were informative and discussed the recent human performance problems and J
self-checking techniques.. Plant staff feedback was open and constructive. In addition, senior management attended proevolution briefings for infrequently performed outage activities in order to place additional emphasis on self-checking techniques. Human performance since the work stoppage has improved. The inspectors concluded that the corrective actions were timely and vital to preventing more significant humaq performance errors.
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Conclusions Human performance was generally good. Station personnel maintained :A low tolerance threshold by identifying numerous minor human performance deficiencirss at the beginning of the Unit 2 refueling outage. ' Management aggressively rer,ponded to these problems with a plant-wide work stoppage to review the problems, improve preevolution bnefing standards, and reenforce self-checking techniques. IncreasrA senior plant management observations of proevolution briefings added emphas!s to self-checking techniques. These timely actions help to prevent more significant human performance error,
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C2 Operational Status of Facilities and Equipment O2.1 Confiouration Control Related to Clearance Activities a.
Inspection Scooe (71707. 62707)
Numerous confguration control discrepancies occurred early during the 1998 extended
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dual unit outage. The inspectors reviewed confguration control practices and the.
automated clearance program used during this Unit 2 refueling outage to determine the effectiveness of corrective actions. Clearances associated with the "A" service water system and the residual heat removal retum isolation valve 2MOV*RHS-720A were reviewed in detail. The review included evaluation of clearance points, examination of the individual clearance sections, and walkdowns of various components.
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Observations and Findinas
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4he computer-based clearance program was implemented in May 1998. The system contained many new features including the ability to identify possible conflicts in clearances prior to issuance. In addition, the new system resulted in improved.
' efficiency and reliability. - This new system, combined with additional SROs and reactor operators (ROs) performing clearance reviews, has facilitated improved configuration control. Some isolated computer related problems occurred during the outage which made various activities time consuming and at times difficult. Corrective actions resolved
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corrective action system.
The selected clearance sections reviewed were properly written with appropriate reviews and signatures. Several minor deficiencies were observed; however, the problems were
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generally identified and corrected prior to conduct of maintenance activities. These deficiencies included failure to identify all work activities and the proper work disciplines during clearance development prior to the outage. Confguration control associated with
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repairs to 2RHS-MOV-720A, including development of a temporary operating procedure to verify isolation boundary integrity, was meticulously maintained.
The inspectors conducted walkdowns of the service water system. The service water valves were found in the proper position and restored to the configuration as defined in the clearance sections. Control room operators accurately updated system drawings to maintain correct configuration tracking during outage activities. Configuration control during infrequently performed surveillance tests (see Section M1.2) was good.
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Conclusions Outage confguration control improved, based on implementation of the computer-based i
clearance system in May 1998, combined with additional clearance reviews by SROs
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and ROs. The clearances associated with the service water system and a residual heat removal valve were properly written and complete.
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- Operations Procedures and Documentation O3.1 Ooerator Loos a.
Inspection Scope (71707)
On several previous occasions (see NRC IR Nos. 50-334(412)/97-04 & 97-11),
operators failed to properly log and track applicable TS limiting conditions of operation (LCO) associated with inoperable feedwater flow transmitters. The inspectors reviewed operators logs during routine control room observations and discussed noteworthy.
issues with the SROs to determine whether appropriate log entries were being made to identify and track TS LCOs.
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Observations and Findings The information documented in the operator logs was comprehensive including entries
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into TS LCOs. The entries were sufficiently detailed to provide effective transfer of information to oncoming control room personnel. This detail was especially important during the Unit 2 refueling outage due to the large work volume being performed and the l
number of infrequently conducted evolutions. The inspectors noted that pertinent issues (problems, unexpected results, and human performance issues) described in the logs were subsequently addressed through CRs.
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Conclusions Operators maintained comprehensive and accurate logs that clearly identified significant activities and applicable TS LCOs. Plant problems described in tlw logs, were effectively transferred into the corrective action system for resolution.
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Quality Assurance in Operations i
07.1 Unit 2 Pre-Outaae Safety Review i
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Inspection Scooe (71707. 37551)
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i The inspectors reviewed the "2R7 Pre-Outage Safety Review" conducted by the Independent Safety Evaluation Group (ISEG), Unit 2 Operations Department personnel, and outage management department personnel.
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Qbservations and Findinos The ISEG conducted a detailed pre-outage safety review, in accordance with Nuclear Power Division Administrative Procedure (NPDAP) 8.26, " Shutdown Safety / Outage Management," Rev. 5.aThe safety review focused on several key safety functions: 1)
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electrical power sources to emergency buses; 2) decay heat removal methods; 3)
- boration control and inventory control; and 4) containment integrity. The review concluded that the refueling outage schedule maximized the key shutdown safety
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function systems available for defense in depth and with sufficient margin to protect both the public and station workers.
- - During the outage ISEG continued to review changes to the schedule to ensure that the s. -
safety margin was still achieved. The control room staff and plant management used shutdown safety status sheets during shift tumover meetings and daily meetings. The operators and managers clearly understood the plant status and importance of key safety parameters.
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Conclusions The ISEG pre-outage safety review verified that the Unit 2 outage schedule provided sufficient safety margin. The ISEG provided a comprehensive ongoing review of work scope and schedule changes and real time assessment of plant risk throughout the refueling outage. Station personnel maintained an awareness of key safety parameters during the outage through effec?ively communication of shutdown safety status sheet information on a shiftly basis.
Miscellaneous Operations issues (92700, 92901)
O8.1 (Closed) Licensee Event Report 50-412/98-13: Inadequate Operating Procedure Leads to Failure to Comply with Technical Specifications.
. This LER discussed a situation where operators did not complete a Unit 2 TS LCO requirement for verifying offsite to onsite attemating current (AC) power supply breaker alignment within the required time period. The inspectors reviewed the LER and surveillance procedure, and conducted interviews to assess the root cause and corrective actions.
TS 3.8.1 requires two physically independent circuits between the offsite transmission network and the onsite Class 1E distribution. The TS action statement, for one offsite circuit inoperable, requires demonstration of the remaining AC sources by breaker alignment and indicated power availability within one hour.
On November 6,1998, at 8:05 a.m., control room operators opened Oil Circuit Breaker-85 for maintenance. This breaker supplies power from the offsite transmission network i
to the Unit 2 Station 2A System Service Transformer (SSST) which then provides power j
to various safety related Class 1E loads. The associated safety related loads remained energized from the Midland Z30 (Z30) line, in accordance with procedures.
The operators declared the 2A SSST inoperable At approximately 10:46 a.m. after an operations procedure writer discovered that the Z30 line could not be credited as source of offsite power. UFSAR Section 8.2.1.1, " Transmission Network," specifically excludes
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.the 230 line as capable of suppiing sufficient power from remote sources This condition resulted in the plant having only one operable offsite AC power source supplying Class 1E loads. As a result, the TS action statement requirement to verify breaker alignment and indicated power avai! ability was not performed within the required one hour tim.
The root cause for the event was an inadequate procedure revision, made in 1991, whic'. ad not verify information contained in the Updated Final Safety Analysis Report (UFSAR) for offsite power. 2OST-36.7, "Offsite to Onsite Power Distribution Breaker
- Alignment Verification," Rev.4, contained a footnote that indicated that the offsite power
. source for the "2A" SSST could be satisfied by the Midland Z30 line.. Subsequent engineering analysis validated the UFSAR statement and confirmed that the Z30 line would not be capable of suppling the required Class 1E loads for the "2A" SSST during emergency conditions. Corrective actions taken for this event included a revision to 20ST-36.7 which removed the footnote and the addition of a caution statement in the operating manual for the 4 kilovolts (kV) station service. The LER properly addressed -
the requirements of 10 CFR 50.73.
The safety significance of this was low as the opposite offsite transmission network was a
available and both emergency diesel generators were operable. Further, the procedure writer showed a very good questioning attitude in identifying the procedure inaccuracy. In this case, failure to perform the required surveillance test within the specified time was a minor violation. The inspector closed this LER.
08.2 (Closed) Licensee Event Report 50-412/98-14: Inadequate Source Range High Voltage Setpoint Leads to Failure to Comply with Technical Specifications a.
Inspection Scope (92700. 92901. 92903)
This LER reported a condition where source range nuclear instrumentation (SRNI)
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channel N32, which was required by TSs to support plant operation, was inoperable.
The inspectors reviewed the LER, design change package (DCP), vendor documentation, and interviewed system engineers to assess the root cause and evaluate the corrective actions.
b.
Observations and Findings During the 1998 Unit 2 extended outage, the inspectors questioned operations personnel concoming a control room deficiency associated with the startup rate meter indicators (see NRC Inspection Report Nos. 50-334(412)/98-05). The resulting investigation by the system engineer revealed that the N32 detector high voltage setting had been set too low when installed in 1995. The calibration procedure had been inadequate as a result of unclear vendor technical manual information.
The Unit 2 Operations Manager had questioned the system engineer conceming the difference in the two SRNI detector readings on several occasions between 1995 and 1998. The system engineer responded that the difference was a result of the difference in sensitivity between the N31 and N32 SRNI detectors and did not pursue the lasue further until October 1998, when he discovered a separate discriminator voltage e calibration problem.-The inspectors noted that the vendor. technical manual information i
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was confusing. By not contacting the vendor to clarify the technical manual information, the system engineer had missed an opportunity to identify and resolve the high voltage setting error prior to the September 1998 Unit 2 restart. The system engineer
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I acknowledged this lesson learned for future use in resolving instrumentation and control issues.
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> The SRNi N32 detector response in the degraded conditic,,1 was evaluated by the Nuclear Engineering Department. The analysis indicated that the reactor trip would have exceeded the maximum allowable value of 1.4 x 105 counts per second (cps) as specified in TS Table 2.2-1, Reactor Trip Instrumentation Trip Setpoints, #5, Source Range, Neutron Flux. The system engineer identified that, at least the last two Unit 2 plant startups were performed with SRNI N32 in this condition. The safety significance was low since the trip function would have occurred, but at a higher than TS allowable j
setpoint and since the UFSAR does not credit the function for mitigating the consequences of an accident. Corrective actions included adjustment of the SRNi N32 detector voltage, revision of the alignment procedures, and correction of the vendor technical manual. Tne inspectors verified the corrective actions listed in the LER were complete. The LER properly addressed the requirements of 10 CFR 50.73.
- Technical specification 3.3.1 and TS Table 3.3-1 require two operable source range i
neutron flux channels in all operational modes (except Mode 1, " Power Operation") when rod withdraw capability exists. Performing heatup and power ascension with only one operable source range detector was a violation of the above TS requirement.
' Compliance was restored in a reasonable time for this licensee identified and non-repetitive, non-willful violation. This Severity Level IV violation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy. (NCV 50-412/99 01-01).
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Conclusions An inadequate calibration procedure, due to unclear vendor technical information and a lack of understanding by the system engineer, resulted in plant operation with one of the two required source range nuclear instruments inoperable. The root cause and corrective actions were appropriate to preclude repetition.- This Severity Level IV
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violation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy and is addressed in the corrective action program as CR 982035.
~ 08.3 Incomplete Condition Reoort investiaations or Corrective Actions
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Insoection Scope (71707. 92901. 92902. 92903)
The inspectors recently observed several instances where corrective action program
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implementation was deficient. The inspectors performed a collective assessment of the
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observed deficiencies to determine whether there was a common cause.
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Observations and Findings
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The inspectors previously documented two indications of corrective action program deficiencies in NRC Inspection Report 50-334(412)/98-11: (1) Over the previous 6
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months,20 percent of the CR investigations were rejected or tabled by the Corrective Action Review Board and (2) Inadequate investigation of meteorological monitoring instrumentation calibration deficiencies revealed a breakdown of the corrective action
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action investigation / implementation deficiencies during this report period:
1.
Corrective actions for VIO 98-01-03 (see Section E8.1) did not properly implement compensatory actions identified in Basis for Continued Operation (BCO) 1-98-012. Although relay crew technicians identified the discrepancy in October 1998, the issue was not evaluated and corrected until identified by the inspectors in March 1999. The inspectors identified several contributing factors including: a poor understanding of TS requirements and plant specific licensing bases by engineers; poor communications between engineering, operations, and maintenance personnel; and a CR was not initiated to resolve the issue.
2.
NRC Inspection Report Nos. 50-334(412)/98-09 identified that design control j
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. measures were not properly established to ensure the design basis DC control voltage requirements for several safety related 4160 voit breaker closing coils wcm met and wrified. The inspectors noted that the completed CR investigation i
( 982188), performed to address the engineering design calculation error, did not directly address the root cause. Engineers had made incorrect assumptions regarding station battery charger performance under design accident conditions,
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but the CR investigation did not reveal why this occurred. Consequently, the
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proposed corrective actions were broad, and did not present a basis for precluoing recurrence. Additional investigation was performed to address the inspectors' observations.
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LER 50-412/98-013 (see Section 08.1) reported that a TS required LCO action to j
verify correct AC source breaker alignment and indicated power availabilty was -
s not performed within the specified time. The event investigation identified the root cause to be an inadequate procedure revision performed in June 1991.
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Procedure writers had failed to review the UFSAR for related offsite power requirements. As a result station procedures did not properly implement TS j
4.8.1.1.1.a.
The investigation for this event identified that procedure writers and reviewers made the same error when revising the procedure in February 1998, despite specific procedure reviewers' guidance to review the applicable licensing basis.
However, neither a CR nor other corrective action was initiated. Although the site implemented other measures during the 1998 extended outages to improve TS surveillance performance, the inspectors questioned whether appropriate corrective action had been taken to address the 1998 procedure revision error.
The inspectors noted that two specific corrective action projects which should
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have identified the subject of this LER, the TS Surveillance Review Team
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(TSSRT) and the UFSAR Verification Project, failed to do so.
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4.
LER 50-412/98-13 (see Section O8.2) reported that the source range channel N32 neutron high flux trip function had been inoperable since 1995. While reviewing this LER, the inspectors questioned why the TS required SRNI channel
-
~ check (channel to channel flux comparison) had not identified the cause of the event eariier. The inspectors subsequently identified that channel check surveillance procedure, 20M-54.3.L5, " Surveillance Verification Log," Rev. 22, did not specify that a SRNI channel to channel comparison be performed as defined in TS. This condition existed from the procedures' origin in 1987 until the date of this LER. The inspectors expressed concem that operators failed to identify this discrepancy during both the event investigation and the 1998 TSSRT
'
effort.
.
The inspectors questioned whether operators were properly performing the TS required channel check, since the operator logs did not sufficiently document the surveillance requirement. The Unit 2 Operations Manager indicated that, while the procedure wording could be more specific, the operators were trained and
. understood the requirements for performing a channel check. The inspectors interviewed several operators and confirmed that they know the proper method to perform SRNI chanael checks. Procedure writers revised 2OM-54.3.L5 to include a comparison between the two channels. In addition, CR 990605 was -
initiated to review other channel check surveillance procedures.
The inspectors expressed concem to station management that the corrective action program had not fully evaluated or resolved the issues listed above, and that the v-
<
examples listed above may be indicative of an underlying performance problem. The inspectors identified several common factors including department manager acceptance of marginal or incomplete CR investigations, insensitivity to TS requirements, and in two instances, hesitancy to initiate CRs. Following discussions with the inspectors, several CRs were initiated to address the individual issues listed above, and a high priority (category two) CR (990600) was initiated to address the overall concem of corrective action program ownership and TS sensitivity. The Senior Vice President - Nuclear -
"
Services Group established a team to evaluate the issues listed above, and recommend corrective actions as appropriate.
c.
Conclusigna The corrective sction program did not fully evaluate or resolve several recent deficient j
conditions including compensatory actions associated with emergency bus degraded voltage instrumentation and TS LCO action and surveillance requirements. The inspectors determined that common factors included department manager acceptance of
!
poor CR investigations, insensitivity to TS requirements, and hesitancy to initiate CRs.
'
Following discussions with inspectors, senior management established a six person team to evaluate the individual corrective action deficiencies and determine whether
- underlying weaknesses exist.
'
.
~*
11. Maintenance M1 Conduct of Maintenance M1.1 Routine Maintenance Observations a.
Inspection Scope (62707)
The inspectors observed selected maintenance activities on important systems and components. The maintenance work requests (MWRs), work orders (WOs), and maintenance planning ccheduling (MPS) observed and reviewed are listed below:
MPS 75814 Control Room Emergency Air Supply Pressure Switch [PS-
.
VS-10582) Calibration MWR 76591 Steam Generator Feedwater Isolation Valve [2FWS-a HVY157A) Operator Repair l
MWR 60482 Auxillary Feedwater Pump [2FWE-T22] Inspection
-
MWR 76118 Control Room Emergency Ventilation System Filte [2HVC-
FLTA252A} Replacement
. MWR 60460 Residual Heat System Valve [2RHS*MOV-720A] Repair
.
MWR 60076 Station Battery 2-1 Replacement
MWR 40336
"B" Quench Sgay Discharge Valve Repack a
MWR 67838 7300 Power Supply Testing
.
. Condenser Steam Dump Valve Repair
.
i b.
Observations and Findinos
- Maintenance activities were performed safely and in accordance with well planned.
maintenance work packages and instructions. Maintenance supervisors were cognizant j
of the work scope and demonstrated good ownership and leadership in the field.
'
The housekeeping controls and cleartness for the work activities performed on
the Auxillary Feedwater Pump,2RHS*MOV-720A, and station battery 2-1 were exceptionally good.
System engineers appropriately incorporated lessons leamed from station battery
testing during the past year and developed a comprehensive 2-1 station battery post-installation test plan.
The work on the Control Room Emergency Ventilation (CREV) filter was
-
appropriately stopped when maintenance technicians identified a discrepancy with the filter gasket. This discrepancy was properly resolved.
_ Failures associated with the process rack power supply testing were properly
-
.
.e entered in the corrective action system. System engineer involvement was active and beneficial in dispositioning issues raised during CREV filter replacement and process rack power supply testin r
- - o
'
The maintenance associated with the Unit i steam dump valves was well
controlled. Temporary Operating Procedure (TOP) 1 TOP-99-01 was well written,
-which allowed the steam dump valves to be tested individually. -
Repair of 2RHS-MOV-720A required a full core off-load and careful assessment of isciation boundaries. Procedure writers developed 2 TOP-99-03, " Verification of Check Valve 2 SIS *145 as Clearance Boundary Point," Rev.1, to verify a check valve was properiy seated and could be used as an isolation boundary. The Onsite Safety Committee (OSC) conducted a thorough review of the TOP prior to authorizing its use.
Proper use of the TOP eliminated the need to fully drain down the refueling cavity for the 2RHS*MOV-720A repair.
c.
Conclusions The nine observed planned maintenance activities, including station battery replacement,
. auxiliary feedwater pump inspection, and residual heat system valve repair, were
,,.
performed safely and in accordance with maintenance work instructions. The work packages, including post-maintenance testing requirements, were good. System engineers actively supported the work activities where appropriate. Maintenance supervisors demonstrated good job. ownership and leadership in the field.
M1.2 Routine Surveillance Observations a.
insoection Scope (61726)
The inspectors observed selected surveillance tests. Operational surveillance tests (OSTs) and Beaver Valley tests (BVTs) reviewed and observed are listed below.
.
- -
10ST-15.3 '
Reactor Plant Component Cooling Water Pump [1CC-P-1C) Operating Surveillance Test, Rev. 9 1/2OST-43.17B Control Room Area Radiation Monitor [RM-1RM-218B]
q
Functional Test, Rev.16 10ST-30.2 Reactor River Water Pump 1 A Test, Rev.16
+
2OST-11.14A Low Head Safety injection (LHSI) Full Flow Test, Rev. 8
2BVT-1.39.1 Station Battery [ BAT *2-1) Service Test, Rev. 3
+
20ST-36.1 Emergency Diesel Generator [2EGS*EG2-1] Monthly Test,
Rev. 24 20ST-11.14B High Head Safety injection (HHSI) Full Flow Test, Rev. 7
b.
Observations and Findinas The surveillance testing was performed safely and in accordance with approved
. procedures. The plant operators were cognizant of the surveillance tests. The proevolution briefings were informative and described the testing sequences appropriately. Communications during the surveillance tests were good and the test procedure sequences were properly followe F
.
'
The inspectors noted that SROs were assigned as test directors for several infrequently performed tests (i.e., LHSl and HHSI full flow tests). Test directors were assigned both on day-shift and on night-shift to assure continuity for tests which ran for more than one
,, shift. In response to several minor human performance errors early in the refueling outage, management placed more emphasis on the preevolution briefings for major evolutions. The inspectors observed that the test directors conducted comprehensive preevolution briefings prior to the LHSI and HHSI full flow tests. Work assignments, field observation methods, test exit criteria, activity risk significance, and industry experience were clearly highlighted during the briefings. Command and control by the test director or his designee throughout the test evolutions were good, c.
Conclusions i
The seven observed surveillance tests were performed safely and in accordance with proper procedures. Management placed more emphasis on preevolution briefings for infrequently performed evolutions following several minor human performance deficiencies observed early in the refueling outage. The assignment of test directors, the quality of preevolution briefings, and test implementation for safety injection full flow tests
were excellent.
M2 Maintenance and Material Condition of Facilities M2.1 Safety Related Heat Exchanoer Proaram Review
a.
Insoection Scooe (62707)
Due to recent problems with the Unit 1 main condenser as a result of a lack of chlorination, the inspectors reviewed the program for monitoring and maintaining the l
performance of the safety related heat exchangers including performance testing.
)
Surveillances tests used to verify safety related heat exchanger performance were reviewed. The inspectors also reviewed commitments to Generic Letter 89-13, " Service Water System Problems Affecting Safety related Equipment."
S.
Observations and Findin_gg l
The preventive maintenance program effectively 6 maintained the safety related heat exchangers. Heat exchanger cleaning and inspections were scheduled in accordance with the MPS system. Inspection results were documented on heat exchanger inspection data sheets and transmitted to system engineers for review. The program is controlled through Maintenance Programs Unit Administrative Manual, (MPUAM) Section 4.27, ' Monitoring of Biological infestations and Fouling of Station Cooling Water Systems," Rev.1.
.The inspectors reviewed MPUAM, Section 4.27, and determined that it comprehensively listed the safety related heat exchangers. Inspection data sheets and MPS sheets evaluated were comprehensive and well documented. The inspectors determined, through interviews with system engineers, that a high degree of engineering involvement T
-.
is placed on safety related heat exchanger performance. System engineers performed most of the inspechons and provided the resultant cleaning instructions to maintenance personnel. System engineers also obtained and documented the results of performance testing on the heat exchangers. The inspectors reviewed, Unit.1 BVT =1.30.3, " River
'e Water Heat Exchanger Performance Program," Rev. 3. The test procedure was comprehensive in evaluating safety related river water heat exchangers. The inspectors also reviewed surveillance tests 10ST-30.12.A(B), " Train A(B) Reactor Plant River Water System Full Flow Test," Rev.11, which verify the required TS flow through the recirculation spray heat exchangers. - The inopectors concluded that safety related heat exchangers were being properly maintained and tested.
c.
Conclusions The preventive maintenance program effectively maintained and performance testing monitored the safety related heat exchangers. System engineers conducted comprehensive performance monitoring and assessment.
M8 Miscellaneous Maintenance issues (92700)
M8.1 (Closed) Licensee Event Reoort 50-412/98-12:- Degraded Station Emergency Battery -
Cell Due to Aging Results in Technical Specification Required Unit Shutdown The inspectors conducted an onsite review of this LER. The November 1,1998, TS required shutdown and immediate corrective actions, were previously documented in 4 -
.
NRC Inspection Report No. 50-334(412)/98-06. The LER accurately described the event, causal factors, and appropriate corrective actions. The inspectors verified that station battery 2-1 was scheduled for replacement during the current refueling outage and station battery 2-2 was scheduled for replacement during the next Unit 2 refueling outage. Temporary modifications were prepared to jumper a cell from station battery 2-2 in the event that a cell became inoperable during the next operating cycle, prior to
-
-
-
battery replacement. The LER properly addressed the requirements of 10 CFR 50.73.
111. Enaineerina E1 Conduct of Engineering E1.1 Devcbsment and Implementation of Desion Chanoes a.
Inspection Scope (37551. 92901. 92903)
The inspectors reviewed two Unit 2 DCPs, observed field installation and testing, and interviewed personnel to evaluate design change quality.
. DCP 2309
. Replacement of 2SWS*SOV-130A(B)
.
DCP 2217 Blender Auto Makeup Workaround (2CHS*FCV-113A)
.
L
.--
_ _ _ - _ - _ _ _ - - _ _ - _ _
_- ____
___
_
..
'
b.
Observations and Findinos DCPs 230g and 2217 each corrected risk significant deficiences which had resulted in
- longstanding operator.workarounds. The Unit 2 service water. system (SWS) pumps can be supplied with seal water from either the filtered water system, which is non-safety related, or from river water. Filtered water is normally aligned to the pump seals since it is cleaner than river water, thereby extending SWS pump seal life. Since the filtered water supply is non-safety related, 2SWS*SOV-130A(B) opens to provide river water to the pump seals upon an accident signal or a loss of filtered water signal. 2SWS*SOV-130A(B) had a history of sticking shut. This design change installed an air operated actuator to improve opening force and installed a ball valve which is better suited for the turbid river water conditions.
The inspectors determined that DCP 230g was well written including a detailed safety evaluation and comprehensive installation test plan. Engineers demonstrated thorough knowledge of the DCP and closely monitored both installation and testing. The valve modification was a good technical solution to address both the dirty river water environment and provide mote valve opening force. Tb inspectors observed good foreign material exclusion controls, configuration controls, and communications while the design change was installed and tested.
The Unit 2 boric acid blender automatic makeup system was designed to provide a mixture of borated water and pure water to make up RCS inventory via the volume
.L control tank. The control valve for the borated water supply had flow and controller characteristics which caesed the valve to fully open when flow was initiated. This resulted in an overboration condition. In addition, the control valve for the pure water had begun to exhibit the same characteristics which could cause an unplanned positive reactivity addition. The design change (DCP 2217) modified the control characteristics of the two valves such that the valve will not fully open when flow is initiated. The inspectors determined that DCP 2217 implemented a reasonable technical solution to.
eliminate the potential overboration and overdilution conditions. Engineers
'"
demonstrated thorough knowledge of the design change, c.
Conclusions Two Unit 2 design changes were properly implemented to correct risk significant deficiencies which had necessitated longstanding operator workarounds. The service water pump seal supply modification was well written including a detailed safety evaluation and comprehensive installation test plan. Engineers demonstrated thorough knowledge of the design change and closely monitored both installation and testing.
Foreign material exclusion controls, configuration controls, and communications were appropriate during design change installation and testing.
.
...
... _ _ _ _ _
_ - _.
- - _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _
_ _ - _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
..
.-
E1.2 Unit 2 In-Service insooction Proaram a.
inspection Scope (IP73753)
The inspectors reviewed the documented scope of the second 10 year interval in-service inspection (ISI) program to determine whether the current inspection program meets the requirements of Section XI, lWB 2410, of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (B&PVC).
b.
Findings and Observations The inspectors found the documented scope of the second 10 year interval, first period,'
inspection to be comprehensive and consistent with the requirements of ASME B&PVC Section XI, lWB 2410. One thousand seven hundred and forty-nine inspection items were planned for the second interval. For the first penod of the second interval,446 -
items were selected for inspection which was within the inspection percentage allowed
. by lWB 2410. During this refueling outage (RFO 7), ig6 of the 446 first period examinations were planned, of which 145 were completed, and 118 reviewed. There were no defects reported as a result of the review. In addition to the planned inspections, ig6 bolted connections were examined for leakage as identified by visual *
observation of boric acid leakage residue. Forty-four of these connections exhibited evidence of leakage and were classified as unsatisfactory. The inspectors determined that the licensee planned appropriate corrective actions for each unsatisfactory bolted connection depending on the location and extent of deterioration.
-
-.
c.
Conclusion
.
Planning and implementation of the second 10 year interval, first period, inspection was
'
consistent with ASME B&PVC Section XI requirements.
- E1.3 Beactor Vess~l Head " Stuck Studs"
>
a.
Insnar* ion Scope (IP73753)
!
!
The inspectors reviewed documentation justifying operation with 3 of 58 reactor vessel i
head-to-flange studs unable to be removed during refueling outages for visual inspection
!
of threads, i
b.
Observatons and Findenas j
\\
Descripton of Problem l
As part of the ISI program, the reactor head-to-vessel flange studs are visually and l
L
- volumetrically inspected for flaws in accordance with the ISI inspection plan. This
'
inspection is performed on a portion of the 58 studs during each outage such that over the three inspection periods of the interval all the studs are inspected. The studs are 6 inch minimum shank diameter, with a design flange thread engagement length of 8.88 l
_ _ _ _ _ _ _ _ _ - _.. _ _
,, _,
...
.
-
.
<
inches, uniformly distributed circumferentially, and numbered consecutively from 1 through 58. The studs are fabricated of SA 540, Class 3, Grade B24, or its equivalent.
The stud material meets the fracture toughness requirements of ASME Section lli and
During review of problem reports, condition reports,10 CFR 50.59 safety evaluations
. and analytic evaluations since 1993, the inspectors found that the licensee reported the inability to remove stud #51 for inspection during RFO 4. At that time, a contractor report R-4504-00-1 determined the~ acceptability of stud operating stresses with stud #51 raised 1.5 inches from its bottomed position in the threaded flange hole.
Subsequently, during the following RFO 5, failed attempts to remove stud #51 resulted in raising stud #512.125 inches from its normal bottomed position. Furthermore, two
. additional studs #25 and #37 were not removable and were fixed 0.25 inches and 2.0 inches from their normal bottomed position in their respective threaded flange holes.
These translated into losses of holding capacity of 2,16, and 17 threads for studs #25,
- 37, and #51, respectively.
Evaluation of Future Operability The inspector reviewed a stud stress evaluation !n contractor report R-4505-00-1 that indicated the loss of the threads in studs #25, #37, and #51 would not increase the stud or flange stresses beyond the allowable ASME code values. Furthermore, the contractor found that the stud stresses would remain within allowable values if the three studs were
,
_.
not active. Aiding in this evaluation of continued operation was the favorable distribution of the fixed studs (not close to each other around tha stud circle), and the favorable evidence of fixed stud load carrying capability resulting from auccessful tensioning of these studs.
Root Cause and 50,59 Safety Evaluation Since the studs could r;ot be removed, the licensee has not yet determined the root cause of stud " sticking." The licensee determined the possible causes include thread pitting, boric acid residue build-up within the stud cavity and threads, manufacturing defects, or damage caused during removal for inspection. However, in a 10 CFR 50.59 evaluation (TER 9336), the licensee justified a procedure change leaving the 3 fixed studs in place for the remainder of plant life. The fixed studs will have volumetric examination, in accordance with ASME Section XI code rules. The evaluation concluded that the change has no effect on design basis accidents,' created no potential for a new type of unanalyzed event, and did not impact the margin of safety. On this basis, the i
licensee concluded that the change does not involve an unreviewed safety question, nor.
does it involve an unreviewed environmental question.-
-The changes to the refueling procedure, allowing the fixed studs to remain in place u..
.
during refueling outages, have been reflected in revisions to the UFSAR, Section 5.3.1.7
-
? Reactor Vessel Fasteners" and UFSAR Gection 5.3.3.7 "in-Service Surveillance." The
. -.....
.
.
_
.
inspectors determined these changes were in accordance with the ASME Code,Section XI rules.
Reactor Vessel Head Stud in-Service inspection The inspection of the studs was not scheduled for this cutage. The inspectors reviewed previous stud inspection results and found that the visualinspection of the threads and the volumetric inspection of the studs using ultrasonic inspection was in accordance with ASME Section XI requirements and that there were no reported stud defects.
c.
Conclusion The licensee completed a 10 CFR 50.59 safety evaluation justifying a refueling procedure change that allowed fixed reactor vessel head closure studs #25, #37, and
- 51 to remain in place during refueling.
E1.4. Unit 2 Steam Generator Inspection e
a.
Inspection Scooe (IP73753)
The inspectors reviewed the results of the Unit 2 August,1998 Westinghouse Model 51-M steam generator eddy-current tube inspection documented in the Framatome Technologies * Technical Summary of Eddy Current Examinations Performed at Beaver
-
t Valley 2", and compared the number of reportable defects with that of previous inspections to determine any increasing trend in tube degradation.
b.
Observations and Findinas During the August,1998 outage, all three Unit 2 steam generators (21 A,21B, and 21C)
with inconel 600 tubes were examined using eddy current tube inspection technology. A L
total of 9881 tube straight sections were examined end-to-end using 0.720" bobbin-coil probes. All 598 of the tight-bend inner row 1 and 2 tubes, and 20 percent of inner row 3
?
tubes were examined using single plus-point magnetically-biased rotating probe coils
(RPC). Distorted bobbin coil indications at support plates, non-quantified bobbin indications, and other indications of interest were further examined using motorized rotating 3-coil (MRPC) probes.
One hundred percent of hot leg top-of-tube-sheet plus-point RPC tube examinations were performed from three inches within the tube sheet to six inches above the tube sheet to cover the height of the sludge pile. Dings / dents at tube support plates were selectively examined with this probe using a voltage-based selection criteria.
The inspection found defective tubes in steam generators 21 A,21B, and 21C that
._
_. required plugging due to pitting (4), outer diameter (OD) inter-granular attack (IGA) at a support plate (1), OD axial crack at the tube sheet (1), OD circumferential cracks at the tube sheet (5), and other defects (2). A total of 13 defective tubes (0.13 percent) were plugged as a result of the August,1998 inspection findings. This total was less than that I
l
_
.
plugged for RFO 6 (63) and RFO 5 (63). The cumulative number of tubes plugged to-date was 260 (2.57 percent).
c.
Conclusion Steam generator eddy current tube examinations were comprehensively performed in accordance with ASME B&PVC Section XI requirements.
E1.5 ISI Observations and Results a.
Insoection Scope IIP 73753)
The inspectors observed the implementation of magnetic and ultrasor'ic inspections of the reactor vessel head to flange weld, reviewed the results of ultrasonic examinations of the reactor shell to flange weld, and reviewed the results of radiographic examinations of several welds used during installation of a replacement valve.
b.
Observations and Findinos Insoections Rec;;;d Durina RFO7 The inspectors observed the non-destructive examination (NDE) of the reactor vessel head-to-flange circumferential weld, item RCS * REV 21-C-1 A, using magnetic
>
a. examination (Procedure MT-201/13) and ultrasonic examination (Procedure UT-306/9).
The inspectors also observed the calibration of ultrasonic transducers, couplant, and electronic signal discrimination equipment. The inspectors noted both examination results were satisfactory and in accordance with ASME Section XI 1989 E.
The inspectors reviewed the NDE results of the reactor vessel shell-to-flange -
circumferential weld, item 2 CRS*.REV 21-C, using ultrasonic examination (Procedure UT 314/2(99-1) and related ultrasonic transducer calibration data. The inspectors noted results were satisfactory and in accc; dance with ASME Section XI 1989 E.
j
As part of the installation of a replacement valve for 2CHS-MOV-289, the inspectors reviewed the NDE results for welds 2CHS-120-F-12A,2CHS-120-F557A, and 2CHS-120-F558A, using radiographic examination (Procedure RT-604). The inspectors noted the results were satisfactory and in accordance with ASME Section lil 1992 E. The
,
inspectors also noted radiographic examination of related " stay" field weld 2CHS-120-10-D-A indicated a porosity defect, which was subsequently removed and satisfactorily repaired.
Review of Qualifications and Certrfications w,.The inspectors reviewed the detailed qualification and certification records of four
-
individuals engaged in NDE on the ISI program. The review indicated that the ISI inspectors were qualified by formal and practical training, and were certified to proper levels (il and lil) of inspection / examination responsibility in different examination
_
..
i
methods (e.g., visual examination, liquid penetrant examination, magnetic particle examination, radiographic examination, or ultrasonic examination).
c.
Conclusio.njg Unit 2 refueling outage number 7 non-destructive examinations were implemented in accordance with ASME B&PVC Section XI and Section lli rules for magnetic particle, ultrasonic, and radiographic examination and were performed by qualified and certified inspectors using acceptable procedures.
E8 Miscellaneous Engineering issues (92901,92902,92903)
'
- E8.1 (Closed) VIO 50-334(412)/98-01-03: Failure to Submit TS Amendment Request in a Timely Manner and implement Adequate Administrative Controls After a Known TS Deficency was Recognized In 1993, engineers determined that the 4 kV and 480 voit emergency bus degraded
..
voltage actuation setpoints listed in TS were nonconservative and would not ensure equipment actuation as required by design. From 1994 to 1998, the licensee failed to request a TS license amendment and failed to property revise station procedures to ensure the actuation setpoints were maintained as required by design. This was a violation of 10 CFR 50, Appendix B, Criterion XVI " Corrective Action." On one occasion
+
the as found instrument setting was below the design analysis allowable value. The
sinspectors reviewed station records and conducted interviews to verify whether all -
'
-
corrective actions stated in the violation response dated May 22,1998, were properly completed.
-
DLC established required administrative controls to ensure adequate emergency bus
<
degraoed voltage setpoints using BCO 1-98-012 (July 1998) and 2-96-011(August 1998)
in accordance with NPDAP 5.7, " Basis for Continued Operation," Rev. 2. TS 3.3.3.4 specifies both an "as-found" a.llowable value (used to determine lastrument operability)
,
,
and an "as-left" trip setpoint ( used to account for setting tolerances). Each BCO
'
specified more restrictive allewable and trip setpoint values than were listed in the TS.
The inspectors determined the BCOs were well written and technically sound. The
)
BCOs were implemented prior to unit restart and were to remain active until TSs were revised to incorporate the correct degraded voltage setpoints. The associated TS amendment requests were submitted to the NRC in January 1999.
The inspectors determined that six of the seven corrective actions for the violation were properly completed. The remaining action, revision of maintenance surveillance procedures (MSP) which implement Unit 1 TS required surveillance tests, was not correctly implemented. The MSP revisions properly addressed the new design allowable values, but did not assure the "as-left" trip setpoint would be within the values specifed in BCO 1-98-12. As a result, between September 17 and October 28,1998, the trip I
u setpoints for two 4 kV and one 480 voit emergency bus degraded voltage relays were not maintained > 93.7 percent of nominal bus voltage, as required by the BCO. The inspectors confirmed that the "as-found" and "as-left" tr;p setpoint values remained within
.
the BCO allowable values and therefore the equipment had remained operable. The most recent "as-left" trip setpoints satisfied BCO 1-98-012 requirements. The safety consequence associated with the erroneous procedure revisions and incorrect "as-left"
-
- trip setpoints was low.eThe inspectors informed engineers of the MSP discrepancies and appropriate procedure revisions were made. Condition Report 990485 was initiated to identify why BCO 1-98-012 had not been properly implemented and establish appropriate corrective actions. The inspectors closed this LER.
IV, Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 Radioloaical Worker Performance (71750)
)
The inspectors performed tours of the Unit 1 and Unit 2 primary auxiliary buildings and the Unit 2 containment building. Workers wore proper dosimetry and protective clothing and observed radiological postings. Health physics technicians effectively controlled
,
high dose radiological areas and provided support for high dose work activities.
Conduct of Security and Safeguards Activities a.
Insoection Scoos (81700)
'
' The inspectors evaluated whether the conduct of security and safeguards activities met the licensee's commitments in the NRC-approved physical security plan (the Plan) and NRC regulatory requirements. Areas inspected included the access authorization program, alarm stations, communications, and protected area (PA) access control of personnel and packages.
b.
Observations and Findinas Access Authorization Proaram. The Access Authorization (AA) program was reviewed to verify implementation was in accordance with applicable regulatory requirements and the Plan commitments. The review included an evaluation of the effectiveness of the AA procedures, as implemented, and an examination of AA records for 19 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, access denial records and applicable procedures were reviewed to verify that appropriate actions were taken when individuals were denied access or had their access terminated.
Alarm Stations. Operations of the Central Alarm Station (CAS) and the Secondary Alarm
- Station (SAS) were reviewed Both alarm stations were determined to be equipped with s
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 that 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 functions.
Communications. 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 Plan.
Protected Area Access Control of Personnel and Hand-Carried Packsoes. On March 9 and 10, during peak activity periods, personnel and package search activities were observed at the personnel access portal. Positive controls were determined tu 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 searched, c.
Conclusions Security and safeguards activities in the areas of access authonzation, alarm stations, communications, and protected area access control of personnel and packages were conducted in s nanner that protected public health and safety.
Status of Security Facilities and Equipment a.
Inspection Scope (81700)
Areas inspected were PA assessment sids, PA detection aids, and perrannel search equipment.
- b.
Observations and Findinos Assessment Aids On March 10, the effectiveness of the assessment aids wac evaluated by observing the PA perimeter on closed circuit television. The assessment sids had good picture quality and zone overlap. Additionally, to ensure the Plan commitments were satisfied, the licensee had procedures in place requiring the implementation of compensatory measures in the event the alarm station operator was unable to properly assess the cause of an alarm.
PA Detection Aids. On March 10, testing was observed of selected intrusion detection
zones in the plant protected area. Through observations and rev'ew of the testing i
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 in the Pla.
Personnel and Packaae Search Eauipment. On March 10, both the routine use and the daily operational testing of the personnel and package search equipment were observed.
Personnel search equipment was being tested and maintained in accordance with
- procedures and the Plan and personnel and packages were being properly searched m...#.
-
prior to PA access.
Observations and procedural reviews determined that the search equipment performed in accordance with procedures and the Plan commitments.
c.
Conclusions Security facilities and equipment in the areas of protected area assessment aids, protected area detection aids, and personnel and package search equipment were well maintained and reliable.
Security and Safeguards Procedures and Documentation a.
Insoection Scope (81700)
Areas inspected were implementing procedures and security event logs.
b.
Observations and Findinas J Security and Proaram Procedures. Review of selected security program implementing
procedures verified that the procedures were consistent with the Plan commitments.
Security Event Loos. The Security Event Logs for the previous nine months were
. reviewed. Based on this review, and discussion with security management, it was determined that the licensee appropriately analyzed, tracked, resolved, and documented safeguards events that the licensee determined did not require a report to the NRC within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
c.
Conclusions Security and safeguards procedures and documentation were being properly implemented. Security Event Logs were being properly maintained and effectively used to analyze, track, and resolve safeguards events.
S4 Security and Safeguards Staff Knowledge and Performance a.
Inspection Scope (81700)
Area inspected was security staff requisite knowledg.
~
b.
Observations and Findinas Sewrity Force Reouisite Knowledoe. A number of SFMs in the performance of their
-
u
. routine duties were observed.s These observations included alarm station operations, personnel and package searches, and exterior patrol alarm response. Additionally,
. SFMs were 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 assignments.
Resoonse Capabilities Review of the Tactical Training Manual, Rev. 3, dated March 10,1997, disclosed that the
'
number of armed responders assigned to fixed defensive positions within predetermined time lines was the same number of armed responders that the licensee specified would be onsite and available in the Fian. Review of drills conducted as part of the training i
program and review of the video tapes of the tabletop exercises conducted during the Operational Safeguards Response Evaluation (OSRE) on March 31 to April 3,1997, disclosed that the licensee was able to successfully protect the preidentified equipment target sets specified in the Tactical Training Manual with the number of responders specified in the Plan.
The OSRE report, dated June 12,1997, specified a number of responders that were used during the OSRE. However, based on the review of the video tapes of the exercises conducted during the OSRE and review of the Tactical Training Manual used
-
a m
-
to conduct the exercises, that number appears to be the number of armed personnel onsite at the time of the OSRE, not the actual number of responders that were used during the drills.
c.
Conclusions.
P*
The SFMs adequately demonstrated the requisite knowledge necessary to effectively implement the duties and responsibilities associated with their position. The licensee demonstrated response capabilities and the number of armed responders available onsite were appropriate and in compliance with the Plan commitments.
S5 Security and Safeguards Staff Training and Qualifications (T&Q)
a.
Insoection Scope (81700)
Areas inspected were security training, qualifications, and training records.
b.
Observations and Findinos Security Trainina and Qualifications (T&Q). On March 9,.T&Q. records of 10 temporary
.,
SFMs hired to support the current outage were reviewed. The results of the review
- indicated that these personnel were trained in accordance with the approved T&Q plan.
l
!
.
Irainina Records. Through review of training records, it was determined that the records were properly maintained, accurate and reflected the current qualifications of the SFMs.
c.
Conclusions Security force personnel were being trained in accordance with the requirements of the T&Q Plan. Training documentation was properly maintained and accurate and the trainirig provided by the training staff was effective.
S6 Security Organization and Administration a.
Inspection Scope (81700)
Areas inspected were management support, managen.
< Yectiveness, and staffing levels.
b.
Observations and Findinas j
Manaoement Suooort. Review of program implementation since the last program inspection disclosed that adequate support and resources continued to be available to ensure er;setive program implementation.
Manaoement Effectiveness. The inspectors reviewed the management organizational structure and reporting chain and noted that the Manager of Security's position in the p
-
organizational structure provided a means for making senior management aware of programmatic needs.
Staffina Levels. The total number of trained SFMs immediately available on shift met the requirements specified in the Plan and implementing procedures.
i c.
Conclusions.
I The leve! of management support was adequate to ensure effective implementation of the security program, and was evidenced by the allocation of resources to support programmatic needs.
S7 Quality Assurance (QA)in Security and Safeguards Activities a.
Insoection Scooe (81700)
Areas inspected were audits, problem analyses, corrective actions, and effectiveness of management controls.
b.
Observations and Findinos Audits The surveillances conducted as part of the 1999 QA Security Program audit and the 1998 Fitness-for-Duty (FFD) audit were reviewed. The 1999 QA Security Program
.
audit was stillin progress at the time of the inspection. Review of the audit checklists and the surveillances that had been conducted as part of the audit disclosed that the audit included all components of the security program and was comprehensive in scope.
- -
- Review of the FFD audit also determined it to be comprehensive in scope. Both audits were found to have been conducted in accordance with regulatory requirements and both audit teams included an independent technical specialist. Findings from the audits were not indicative of program weakness and implementation of corrective actions for the findings were generally to effect program enhancements.
Problem Analyses. The inspectors reviewed data derived from the security department's self-assessment program. Potential weaknesses were being properly identified, tracked, and trended.
Corrective Actions. The inspectors reviewed corrective actions implemented by the licensee in response to the QA audits and self-assessment program..The corrective actions were effective.
Effectiveness of Manaaement Controls. The inspectors observed that programs were in place for identifying, analyzing, and resolving problems. They include the performance of annual QA audits, a departmental self-assessment program, and the use of industry-data, such as violations of regulatory requirements identified by the NRC at other facilities, as a criterion for self-assessment.
c.
Conclusions The Fitness-for-Duty and Security Program audits were comprehensive in scope and depth, audit findings were reported to the appropriate level of management, and the iaudit program was being properly administered. In addition, a review of the documentation applicable to the self-assessment program indicated that the program was being effectively implemented to identify and resolve potential weaknesses.
V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on March 25,1999. The licensee acknowledged the findings presented.
The licensee did not indicate that any of the information presented at the exit meeting was propnetar.
~
X2 Management Meeting Summary On March 11,1999, a meeting, open for pubic observation was held at the Beaver Valley Power Station.- NRC personnel from the Office of Nuclear Reactor Regulation (NRR) and the Site Resident inspector staff met with Mr. James E. Cross, President, Generation Group, and other members of his staff to discuss the corrective action plan and schedule for correcting design deficiencies of various small bore piping supports on Beaver Valley Power Station Unit 1.
-_
_____ _ _ _ _ _ _ _ _ _ __ ___-_ _ _ --
___ _____
.
.
INSPECTION PROCEDURES USED
- IP 37551:
Onsite Engineering IP 61726:. Surveillance Observation
.-
IP 62707:
Maintenance Observation IP 71707:
Plant Operations IP 71750 Plant Support IP 73753 in-Service inspection IP 81700:
Physical Security Program for Power Reactors IP 92700:
Onsite Follow-up of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92901:
Follow-up - Operations IP 92902:
Follow-up - Maintenance IP 92903:
Follow-up - Engineering
.
e
c
.
'
ITEMS OPENED, CLOSED AND DISCUSSED Opened / Closed
,
l 50-412/99-01-01 NCV Inadequate Source Range High Voltage Setpoint Leads to Failure to Comply with Technical Specifications (Section O8.2)
Closed 50-412/98-13 LER Inadequate Operating Procedure Leads to Failure to Comply with Technical Specifications (Section 08.1) '
50-412/98-14 LER Inadequate Source Range High Voltage Setpoint Leads to Failure to Comply with Technical Specifications (Section 08.2)
'50-412/98-12 LER Degraded Station Emergency Battery Cell Due to Aging Results in Technical Specification Required Unit Shutdown (Section M8.1)
' 50-334(412)/98-01-03
< VIO Failure to Submit TS Amendment Request in a Timely Manner and implement Adequate Administrative Controls After a Known TS Deficiency was Recognized (Section E8.1)
l
..
'
LIST OF ACRONYMS USED-AA Access Authorization AC
. Alternating Current.
ASME American Society of Mechanical Engineers B&PVC.
Boiler and Pressure Vessel Code-BCO Basis for Continued Operation BVPS Beaver Valley Power Station BVT~
BeaverValley Test CAS Central Alarm Station CFR Code of Federal Regulations cps Counts Per Second CR Condition Report CREV Control Room Emergency Ventilation DCP Design Change Package DRP Division of Reactor Projects FFD
_ -. Fitness-for-Duty HHSl High Head Safety injection IGA Inter-Granular Attack ISEG Independent Safety Evaluation Group ISI In-service Inspection kV Kilovolts LER Licensee Event Report
.LHSI Low Head Safety injection MPS Maintenance Planning Schedule
,
MRPC Motorized Rotating 3-Coil Probe MSP-Maintenance Surveillance Procedure j
MPUAML Maintenance Programs Unit Administrative Manual MWR Maintenance Work Request
'NCV-Non-Cited Violation NDE Non-destructive Examination NPDAP Nuclear Power Division Administrative Procedure NRC United States Nuclear Regulatory Commission NRR~
Nuclear Reactor Regulation OCB Oil Circuit Breaker OD Outer Diameter OSC Onsite Safety Committee OSRE Operational Safeguards Response Evaluation
OST Operational Swveillance Test PA Protected Ares QA Quality Assurarx.:
QSU Quality Services Unit q
RCS hector Coolant System
{
' Refueling Outage -
'
-
RO Reactor Operator RP&C Radiological Protection and Chemistry RPC Rotating Probe Coil
.
.
SAS'
Secondary Alarm Station SFM Security Force Member SPEAP System and Performance Engineering Administrative Procedure SRNl.
. Source Range Nuclear instrumentation
'SRO Senior Reactor Operator
,
SSST Station System Service Transformer SWS Service Water System T&Q
. Training and Qualification the Plan NRC-Approved Physical Security Plan TOP Temporary Operating Procedure l
TS Technical Specification TSSRT.
Technical Speerfication Surveillance Review Team
~UFSAR Updated Final Safety Analysis Report VIO Violation WO Work Order
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