IR 05000334/1999004
| ML20211A519 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley  |
| Issue date: | 08/24/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20211A516 | List: |
| References | |
| 50-334-99-04, 50-412-99-04, NUDOCS 9908240066 | |
| Download: ML20211A519 (32) | |
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U. S. NUCLEAR' REGULATORY COMMISSION
REGION I
License No DPR-66, NPF-73 Report No /99-04, 50-412/99-04 Docket No ,50-412 Licensee: Duquesne Light Company Post Office Box 4 Shippingport, PA 15077 -
Facility: Beaver Valley Power Station, Units 1 and 2 Inspection Period: June 13,1999 through July 24,1999 l
Inspectors: D. Kern, Senior Resident inspector !
G. Dentel, Resident inspector l G. Wertz, Resident inspector A. Lohmeier, Senior Reactor Engineer i
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Approved by: P. Eselgroth, Chief !
Reactor Projects Branch 7 I
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9908240066 990818 PDR ADOCK 05000334 j G PM ,
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EXECUTIVE SUMMARY Beaver Valley Power Station, Units 1 & 2 NRC Inspection Repoit 50-334/99-04 & 50-412/99-04 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a 6-week period of resident inspection; in addition, it includes the results of an announced inspection by a regional engineering inspecto Ooerations
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On July 16, Unit 2 operators took prompt action to isolate an electrical fault and de-energize the 2DF emergency 4 kilovolt electrical bus. The nuclear shift supervisor and assistant nuclear shift supervisor quickly defined priorities and maintained orderly )
command and control. Coordination between system engineers, maintenance l technicians, and operations personnel to safely restore the 2DF bus and associated loads was outstanding. Operators safely completed a technical specification required shutdown on July 18. (Section 01.2)
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Operations management did not take timely action to ensure two problems associated with the July 18 Unit 2 forced shutdown, were addressed for Unit 1 applicabilit Specifically, some Unit 1 operators were not trained on or aware of procedure revisions i for loss of reactor coolant pump seal cooling and emergency diesel generator 1-1 cooling was not thoroughly evaluated until questioned by the inspectors. (Section 01.3)
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The operation manual procedure change backlog was high (1700) but decreasing. The changes not yet incorporated, although not critical for performance of the procedures, required operators to compensate through pre-evolution briefings or additional l compensatory actions such as using partial procedures and caution tags. These actions j placed additional burdens on the operating crews and were a type of operator work - !
around. (Section O3.1) l
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Two operating crews responded well during simulator training scenarios in their !
identification of equipment failures and emergency operating procedure usag Simulator instructors were knowledgeable of the facility and effectively used lessons learned and industry information during the training. Fidelity issues with the simulator and the control room were effectively tracked and resolved. (Section 05.1) !
In April 1999, operators properly evaluated a problem with the Rod Control system and
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tripped the reactor. The Licensee Event Report was accurately written and corrective actions were generally comprehensive. (Section 08.1)
Maintenance l
Long standing oil leaks on the Unit 1 charging pumpa have not been corrected. Operator ;
complacency due to the longstanding naiure of the problem resulted in tour operators not initiating deficiency tags for significant oil leaks. Recommended long term actions to ii
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Exec. Summary (cont'd) I address charging pump reliability were appropriate, but had not been schedule (Section M2.1) -
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The Unit 1 and 2 auxiliary feedwater systems were in overall good material condition as !
demonstrated by high maintenance rule system availability and low backlog of work orders. . Open engineering items were properly prioritized and tracked. (Section M2.2)
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Work delays for several Unit 1 activities either increased plant risk or required operations personnel to change their planned schedule and make additional plant manipulation Several factors contributed to poor work schedule implementation including operations and maintenance manpower constraints, poor communication between operations and -
maintenance personnel, untimely or incomplete work package planning, and poor quality pre-job walkdowns. The poor work schedule implementation represented a weaknes (Section M4.1)
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' In March 1999, poor planning and failure by maintenance personnel to recognize the ,
importance of chain hoists to support the Unit 2 containment equipment hatch was the i root cause of the hatch not being fully closed during fuel movement. This Severity Level i 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 ,
990536. (Section M8.1) I i
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System and design engineers provided good support and properly evaluated emergent Unit 2 shutdown issues such as check valve leakage in the safety injection and auxiliary feedwater systems. (Section E1.1)
The industry Operating Experience (IOE) program instruction was comprehensive and effectively managed and backlogs were reduced by 30 %. Engineers and operations personnel understood the IOE program and actively used the IOE databas Evaluations were typically thorough, technically sound, and clearly documented in IOE Positions Statements. Application of industry information regarding electrical circuit breaker maintenance and testing was a strength. lOE engineers actively communicated station issues which held potential generic industry interest. (Section E2.1)
Licensee identification of three recent violations of technical specification (TS) setpoint or calibration requirements demonstrate improved questioning attitudes by station personnel. However, they also demonstrate that previous activities such as the 1997-1998 TS surveillance review project and the ongoing Updated Final Safety Analysis Report verification project were not of sufficient depth to identify these TS non-compliances. Programmatic corrective actions, including continued Engineering Safety Principles training were adequate to improve station personnel's awareness of TS requirements. (Section E8.2)
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s Exec. Summary (cont'd) .
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The Long-Standing Problem Review Team effectively selected, prioritized, and resolved long-standing equipment problems affecting the efficiency, reliability, and safety of Beaver Valley Power Station plant operations. The completed resolutions to the long-standing equipment problems were technically sound. The problems in process of resolution were being addressed in a careful and timely manner commensurate with their difficulty and safety significance. (Section E8.3)
Plant Support -
A health physics technician, using a questioning attitude, identified that the Unit 2
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containment equipment hatch was not fully closed during fuel movement in March 199 (Section M8.1) l l
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. TABLE OF CONTENTS Page EXECUTIVE SU M MARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii TABLE OF CONTE NTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v 1. Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 g 01 Conduct of 0perations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 L 01.1 General Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 01.2 Unit 2 Loss of Emergency 4 Kilovolt Electrical Bus and Forced Shutdown
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.......................................... ............. 1 L 01.3 . Assessment of Unit 2 Problems at Unit 1. . . . . . . . . . . . . . . . . . . . . 3 03- Operations Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 l O3.1 Procedure Change Backlog Review . . . . . . . . . . . ...............4
! 05 ' Operator Training and Qualifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 05.1 Unit 2 Simulator Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 08 Miscellaneous Operations issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 08.1 (Closed) Licensee Event Report 50-334/99-07 . . . . . . . . . . . . . . . . . . 6 l l . Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
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M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
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M1.1 Routine Maintenance Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 M1.2 Routine Surveillance Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 M2 Maintenance and Material Condition of Facilities and Equipment . . . . . . . . 9 M2.1 Material Condition of the Unit 1 Charging Pumps . . . . . . . . . . . . . . . . . 9 M2.2 Auxiliary Feedwater System Review . . . . . . . . . . . . . . . . . . . . . . . . . . 9 M4 Maintenance Staff Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . 11 M4.1 Ineffective Maintenance Work Control Delays Corrective Maintenance
........................................................ 11 M8 Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 M8.1. (Closed) LER 50-412/99-03 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 111. Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 E Response to Emergent Shutdown issues . . . . . . . . . . . . . . . . . . . . . . 13 E2 Engineering Support of Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . . 14 E Industry Operating Experience Program . . . . . . . . . . . . . . . . . . . . . . . 14 E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 E (Closed) Licensee Event Report (LER) 50-334/99-03 . . . . . . . . . . . . 16 E8.2 (Closed) LER 50-412/99-04 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 E8.3 Resolution of Long-Standing Engineering Problems ............ 17 V. Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 X1 Exit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 l -X2 Licensee Management Reorganization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 g
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lNSPECTION PROCEDURES USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 ITEMS OPENED, CLOSED AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 I LIST OF ACRONYMS USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 a
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Report Details Summarv of Plant Status Unit 1 began this inspection period at 100% power and remained at or near full power throughout the inspection perio Unit 2 began this inspection period at 100% power. On July 14, service water supply to emergency diesel generator (EDG) 2-2 dropped below its required minimum flow and was declared inoperable. The plant reduced power to approximately 65% power on July 16 when electrical problems were' encountered while performing a post maintenance surveillance test on ,
EDG 2-2. Troubleshooting did not resolve the electrical problems on EDG 2-2 within the 72- j hour technical specification (TS) allowed outage time (AOT) and operators initiated a plant
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shutdown at 8:21 p.m. on July 17. The main generator separated from the off-site electrical distribution grid at 1:13 a.m. on July 18. The plant entered Mode 5 (Cold Shutdown) at 5:21 p.m. and remained in Mode 5 through the remainder of the inspection perio . Operations 01 Conduct of Operations l
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 I safety-conscious; specific events and noteworthy observations are detailed in the sections belo .2 Unit 2 Loss of Emeraency 4 Kilovolt Electrical Bus and Forced Shutdown Insoection Scope (71707. 93702)
Unit 2 experienced a loss of emergency 4 kilovolt (KV) bus which resulted in a temporary loss of cooling to the reactor coolant pump (RCP) seals and degraded electrical power
. supplies. The inspectors responded to the control room and monitored plant restoration to determine whether operators maintained plant safety, Observations and Findinas On July 14 at 9:57 p.m., emergency diesel generator (EDG) 2-2 was declared inoperable due to inadequate service water (SW) cooling flow to the EDG heat exchanger. After identifying the cause to be the accumulation of Zebra mussel and Asiatic clam shells on the heat exchanger tube sheet, station personnel cleaned the heat exchanger and
- initiated a fullload EDG 2-2 surveillance test as a post maintenance test. Details of the SW heat exchanger fouling problem and the associated clam / mussel mitigation program i
are documented in NRC Inspection Report Nos. 50-334(412)/99-0 .
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2 On July 16 at 5:29 p.m., an electrical fault occurred during the EDG 2-2 full load test, which opened the supply breaker between the emergency and normal 4kV electrical busses. Operators observed degraded 2DF bus voltage and EDG 2-2 output voltage, and manually opened the EDG output breaker to protect safety related equipment. This action was appropriate and de-energized the 2DF electrical bus. The loss of 2DF bus resulted in temporary interruption of reactor coolant pump (RCP) seal injection flow, loss
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of thermal barrier cooling to two RCPs, two inoperabie 125 voit station battery chargers, the eventual inoperability of the two associated 125 voit station batteries, and initiation of a TS 3.0.3 required plant shutdown from 100% reactor powe I The inspectors arrived in the control room about 5 minutes after the loss of the 2DF bus, observed operators stabilize the plant, and monitored field activities to restore the 2DF bus. Operators had restored RCP seal injection flow by this time, but did not realize that thermal barrier cooling to the 'B' & 'C' RCP seals had also been lost. An issue regarding operators' response to the loss of RCP seal cooling, including use and prioritization of alarm response procedures is discussed separately in NRC Inspection Report Nos. 50-334(412)/99-0 The nuclear shift supervisor (NSS) and assistant nuclear shift supervisor (ANSS) quickly defined priorities and maintained orderly command and control. The ANSS focused on directing control room activities, maintaining stable plant conditions, and ensuring TS requirements were met. The NSS focused on restoration of the 2DF bus and associated safety related equipment. The clear division of responsibilities supported the safe and timely restoration of the 2DF bus. Coordination between system engineers, maintenance technicians, and operations personnel to safely restore the 2DF bus and associated loads was outstanding. Operators re-energized the 2DF bus, restored '
battery 2-4 and battery chargers 2-2 and 2-4 operability and terminated that plant .
shutdown at 10:18 p.m. The plant was maintained at 65 % reactor power while l technicians investigated the cause of the electrical fault. Station personnel were unable i to conclusively identify the cause of the fault and completed a TS 3.8.1.1 required i shutdown at 5:21 p.m. on July 1 j c. Conclusions On July 16, Unit 2 operators took prompt action to isolate an electrical fault and de-energize the 2DF emergency 4 kilovolt electrical bus. The nuclear shift supervisor and assistant nuclear shift supervisor quickly defined priorities and maintained orderly command and control. Coordination between system engineers, maintenance technicians, and operations personnel to safely restore the 2DF bus and associated loads was outstanding. Operators safely completed a technical specification required ,
shutdown on July 1 i I
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01.3 esessment of Unit 2 Problems at Unit 1 Inspection Scope (62707) i Following the ' July 18 forced Unit 2 shutdown, station management identified several l issues to be evaluated and corrected prior to unit restart. Some of the icsues applied to )
Unit 1 (operating at 100% reactor power) as well. The inspectors reviewed procedures, conducted interviews, and observed field activities to determine whether the issues were properly addressed at Unit Observations and Findings i
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in mid July, Zebra mussel and Asiatic clam shells fouled the Unit 2 EDG heat exchangers (see NRC Inspection Report Nos. 50-334(412)/99-07). During evaluation of this issue, station management realized that Unit 1 could potentially be effected and directed that SW flow to the Unit 1 EDG heat exchangers be evaluated. During a July 16 ;
conference call, station management indicated their intention to run SW flow through !
each Unit 1 EDG heat exchanger to verify they were not fouled. Response to a related j Unit 2 event and untimely development of acceptance criteria by the engineering staff
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delayed flow testing until July 7/22. The inspectors observed the flow test through EDG 1-2. System engineers closely monitored the test and correctly determined that the EDG 1-2 heat exchanger was not foule Based on the successful EDG 1-2 flow results and trending of other selected Unit 1 heat exchanger performance, system engineers concluded that it was unnecessary to monitor flow through EDG 1-1. The NSS agreed and canceled the EDG 1-1 flow test. The inspectors determined that the basis for canceling the EDG 1-1 flow test was not adequately supported. Unit 2 SW heat exchangers (except EDG 2-2) had also indicated no flow degradation when first checked, yet both Unit 2 EDGs became fouled with shell At this time, the licensee did not understand the exact method which caused the fouling of the EDG 2-1 and 2-2 heat exchangers. The potential for clams and mussels to be present in SW branch piping to the EDG heat exchangers had not been fully addresse l The incpectors met with the System Engineering Department manager and the NSS and 1 questioned their basis for concluding that SW cooling to the Unit 1 EDGs remained operable.- The response did not address the inspectors' observations and the potential
, causes for the SW fouling which were adversely affecting Unit 2. The NSS directed that the flow test be performed on EDG 1-1 the following day to address the inspectors questions. The test was successfully performed on July 2 l While evaluating the July 16, Unit 2 loss of electrical bus event, operations personnel determined that certain procedures did not direct appropriate operator response to a loss of RCP seal cooling event.l Two Unit 1 alarm response procedures and an abnormal .
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operating procedure were revised. The most important change was intended to ensure
- that operators would manually trip the reactor and affected RCP if both seal injection and thermal barrier cooling were lost to a RCP for greater than 2 minutes. The inspectors
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determined the procedure revisions wers appropriate. Senior station management considered these to be important changes as discussed with the NRC staff on a July 19 !
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conference c.W. The inspectors verified that the procedure changes were made in a
- timely manner. However, while conducting control room observations, the inspectors
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changes. Although operations management had put the revisions in effect, some of the operations crews had not been briefed or trained on the revisions. The inspectors addressed this concern with the Ge 'ral Manager of Nuclear Operations who took action to ensure each crew was aware of the revisions.
'- Conclusions Operations management did not take timely action to enst.re two problems associated with the July 18 Unit 2 forced shutdown, were addressed for Unit I applicabilit Specifically, some Unit 1 operators were not trained on or aware of procedure revisions for loss of reactor coolant pump seal cooling and emergency diesel generator 1-1 l cooling was not thoroughly evaluated until questioned by the inspector Operations Procedures and Documentation O3.1 Procedure Chanae Backloa Review Insoection Scope (71707) -
The inspectors examined the large outstanding backlog of operating manual change requests (OMCRs) for impact on operators and quality of procedures. This was reviewed in respo1se to the procedure deficiencies identified during the Unit 2 refueling 1 outage and previous inspection reports. The inspectors reviewed a sample of OMCRs and examined long term backlog reduction plan i Observations and Findinas On July 7, the OMCR backlog was at 1700 OMCRs. The inspectors examined 146 OMCRs in ten risk significant systems as defined in the licensee's maintenance rule program. The inspectors did not identify any significant changes that would affect immediate operability of systems or place the plant in an unsafe condition. The backlog consisted of good enhancements identified by operating crews to improve the quality of the procedures. The changes not yet incorporated, although not critical for performance of the procedures, required tne operators to compensate through pre-evolution briefings or additional compensatory actions such as using partial or " blocked out" procedures ;
and caution tags. These actions placed additional burdens on the operating crews and i were a type of operator work around. Other pending changes provide improved TS applicability / references and improved reactivity management information/ steps. The
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changes would add an additional barrier to identify the proper TS and to prevent ,
unplanned reactivity actions. One change was associated with a refueling water storage i tank level setpoint change that had already been physically changed Based on the inspectors' questions, the change was being processed at an appe pate higher priority.
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in January 1999, seven contractors were added to the operation procedure group to Ll L
reduce the backlog. The OMCR backlog was reduced by 300 since January. The goal u to decrease the backlog to 500 by November was not expe:ted to be met based on discussion with the operations procedure group supervisor. The supervisor stated that a j more realistic goal would be 900 by the end of the year. Current plans are to add further contractor support to reduce corrective action and OMCR backlog through Novembe The inspectors concluded that progress was being made on the backlog and continued management attention was needed in this area.
l Conclusions The operation manual procedure change backlog was high (1700) but decreasing. The changes not yet incorporated, although not critical for performance of the procedures, I
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required operators to compensate through pre-evolution briefings or additional compensatog actions such as using partial procedures and caution tags. These actions placed additional burdens on the operating crews and were a type of operator work aroun Operator Training and Qualifications 05.1 Unit 2 Simulator Observations a.- Insoection Scooe (71707)
The inspectors reviewed simulator training for Unit 2 licensed operators. The inspectors i
observed simulator training for two crews, reviewed fidelity issues associated with the j simulator, and examined use of lessons learned in training.
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l The Unit 2 licensed operators responded well to the simulator scenarios. Instrument and equipment failures were identified in a timely manner. Emergency operating procedures were properly utilized and followed. Communication among the operating crew was adequate, although some instances of poor communication (e.g., not using 3-way communication) were observed. The operators were generally self-critical during the evaluations and critiques. Instructors were knowledgeable about the facility and effectively identified problems and discussed the issues with tr.e operators. Lessons leamed and industry information were discussed during the trainin The inspector reviewed both the process and the backlog of fidelity issues with the simulator. The process, established in January 1998, was comprehensive for tracking and resolving fidelity issues identified by the operating crews and simulator instructor One fidelity issue was discussed during the training session observed. During changes in letdown orifice configuration, the pressurizer level controller is more responsive in the
. simulator than in the control room. This contributed to an event in the control room on May 12,1999. A newly licensed operato changed the letdown configuration and pressurizer pressure (and level) dropped Niow the TS 3.2.5.b limits (departure from I
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nucleate boiling). Pressure and level were restored quickly. Therefore no safety consequences was attributed to this event. The corrective actions to address the event did not include addressing the fidelity issue. Based on the NRC concems and the operator questions, a fidelity item was initiated and was being evaluated for either plant changes or simulator changes. The absence of corrective actions to this one fidelity issue was a deficiency of the correction action system, Conclusions Two operating crews responded well during simulator training scenarios in their
! identification of equipment failures and emergency operating procedure usag Simulator instructors were knowledgeable of the facility and effectively used lessons l leamed and industry information during the training. Fidelity issues with the simulator l ' and the control room were effectively tracked and resolved.
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l 08 Miscellaneous Operations issues 08.1 (Closed) Licensee Event Reoort 50-334/99-07: Manually initiated Reactor Trip During
' Pre-Planned Shutdown inspection Scope (92700. 92901. 92902)
The inspectors performed an onsite review of the LER and an assessment of the root '
! cause analysis and corrective actions .
I Observations and Findinos On April 13 at 3:38 a.m., while inserting control rods during a planned, controlled l shutdown of Unit 1 for a surveillance outage, Control Bank (CB)"A" did not insert during l a continuous rod insertion. The reactor was shutdown in Hot Standby (Mode 3) with i CB's "C" and "D" fully inserted and CB "B" inserted 100 steps. CB "A" rods were fully out of the reactor core. The " Rod Control Urgent Failure" alarm annunciated and further rod motion was inhibited. The Nuclear Shift Supervisor was notified by the Reactor Operator of the condition and dispatched maintenance technicians to investigate the Rod Control (RC) system. Preliminary investigation identified a potential rod control printed circuit i
card failure. The Reactor Engineer was consulted and confirmed that the reactor was shutdow Operators tripped the reactor at 4:27 a.m. and all control rods inserted fully. The event was documented in the corrective action program through condition report (CR) 99091 The CR was well written with good detail including operator actions, communications between groups, and associated time The investigation identified that a possible cause was overheating of the RC circuit boards. Visual examination identified that one of the firing cards in the RC circuit evidenced signs of overheating. Offsite testing was performed at elevated temperatures but no failures were identified. The vendor test report, however, indicated that evidence
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of elevated temperatures which could have caused RC circuit card problems was eviden The LER was accurately written. The root cause investigation identified previous problems with the RC circuit cards in 1985 - 1987 time frame caused by elevated temperatures in the RC cabinets. The resolution was installation of the RC cabinet air conditioning (AC) cabinets. On February 2,1999, the RC cabinet AC associated with the suspected RC circuit card failure was identified as not working. The work order was categorized as " Routine" and given a priority 4 to be worked into the 12 week schedule, According to Nuclear Power Department Administrative Manual 7.15, " Initiation of a Work Request," Rev. 2, the work order should have been categorized as " Expedite" and given a priority 3 and added to the schedule by the work week manager as resources w. e availabl The root cause comprehensively addressed the past RC panel circuit board problems,-
card failure linkage to elevated RC cabinet temperatures, and the February failure of the AC cabinet. The corrective actions were effective in resolving the immediate proble Engineers correctly determined that this event resulted from a maintenance preventable functional failure of the ventilation system (rod control AC cabinets). However, corrective actions to resolve the improper prioritization of the RC panel AC work request did not address future personnel changes. Work order prioritization is performed by the Work Management Center (WMC) Senior Reactor Operator (SRO). Although corrective i actions were in place to train the current WMC SRO's, nothing was in place to train future WMC SRO's. The WMC SRO position is a rotational position with SRO's coming i from the operating shifts to support schedule development. The inspectors discussed !
this issue with the WMC Director who recognized the concem and plans to disseminate the information to a broader range of members in the planning proces c.' Qgnolutions in April 1999, operators properly evaluated a problem with the Rod Control system and tripped the reactor. The Licensee Event Report was accurately written and corrective actions were general!y comprehensiv II. Maintenance M1 Conduct of Maintenance ;
M1.1 Routine Maintenance Observations Insoection Scope (62707) j The inspectors observed selected maintenance activities on important systems and components.- The maintenance work order (WO), and work request (WR) activities observed and reviewed are listed belo ;
= WO 98-074410 Quench Spray Chemicalinjection Pump repair
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WR 076446 Containment instrument Air Compressor replacement
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WO 99-203706 Safety injection Pump 1B oil change Observations and Findinas Maintenance activities were generally performed well. However, planning problems I were observed on the repair of the 1QS-P 40. The SI pump 1B work also encountered delays. Both of these maintenance activities were time sensitive LCO's. See section M4.1 for additional detail Conclusions The activities observed and reviewed were performed safely and in accordance with proper procedures. Inspectors noted that an appropriate level of supervisory attention was given to the work depending on its priosity and difficult M1.2 Routine Surveillance Observations (61726)
- Insoection Scoos (61726)
l The inspectors observed selected surveillance tests. Operational surveillance tests (OSTs), Temporary Operating Procedures (TOP) were reviewed and observed by the inspectors are listed belo TOP-99-04 *EDG 1-2 Fuel Oil Transfer Pumps Post Meintenance ,
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10ST-13.10A' %wical injection System Valve and Pump Operability l Check - Train A," Rev.10 l
- 10ST-3 " Motor Driven Fire Pump Operation Test," Rev.10 2 OST-11.2
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" Low Head Safety injaction Pump [2 SIS *P21 B) Test," Re l I Observations and Findinas l Surveillance testing was performed safely and in accordance with proper procedure During post maintenance testing (PMT) of the quench spray chemical injection pump, communication problems between the plant operator and condition monitoring technicians resulted in the pump being started without technicians present to monitor vibrations. Consequently, the PMT had to be re-performed to verify excessive pump vibration had been corrected. In addition, the inspectors identifed several minor NaOH j leaks. Deficiency tags were written to correct the leal , Conclusions Surveillance testing was performed safely and in accordance with proper procedure )
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M2 Maintenance and Material Condition of Facilities and Equipment
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M2.1 Material Condition of the Unit 1 Charaina Pumos l Inspection Scooe (62707) ;
The inspectors observed the material cordition of the Unit One Charging Pumps during routine plant observations noting equipment deficiencies, housekeeping and general material condition of the equipmen Observations and Findinas During a tour on July 4 of the Unit 1 charging pumps, the inspectors noted that most of
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the "A" pump and motor skid base was heavily coated with oil. The oil appeared to come l from various threaded fittings on the oil system. The inspectors did not observe any i other housekeeping or equipment deficiencies. The inspectors observed similar oil leaks l on the "B" and "C" pump skids. When the inspectors questioned the NSS about the lack
- of deficiency tags for the oil problems, it was discovered that no deficiency tags existe The NSS initiated deficiency tags and wrote CR 991610 to record the continuing nature of the oilleaks.
l The inspectors discussed charging pump material condition, including the continued oil leak problem, with system engineers. The engineers agreed that the current oil leakage from threaded fittings could mask more serious material problems. Repeated equipment outages to repair the oi! leaks have increased pump unavailability hours, yet total system availability remained within maintenance rule perfommnce criteria. Design change package (DCP) 2379 was recently aporoved to replace the threaded fittings with compression fittings. This DCP awM.4 scheduling and funding and is being tracked by CR 980634-03. The inspectors also noted that the "A" charging pump operating time was being scheduled for replacement during or prior to the next refueling outage due to excessive operating time (approximately 57,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br />).
I Conglysion Long standing oilleaks on the Unit 1 charging pumps have not been corrected. Operator complacency due to the longstanding nature of the problem resulted in tour operators not
! initiating deficiency tags for significant oil leaks. Recommended long term actions to l address charging pump rel! ability were appropriate, but had not been scheduled.
l M2.2 Auxiliary Feedwater System Review Inspection Scope (71707. 62707. 37551)
- The inspectors completed a overall system review and system walkdown of the Unit 1 and Unit 2 auxiliary feedwater (AFW) systems.' The inspectors examined outstanding work orders (WOs), egineering memorandums, design change packages, basis for continued operdon, and temporary modifications as part of the system health revie i
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l The inspr tors verified valve lineups, remote indicators, and overall condition during the l l system walkdown. In addition, the inspectors reviewed the updated final safety analysis !
report (UFSAR) for design basis informatio b. ' Observations and Findinas
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The AFW systems were in good material condition as shown by the limited number of outstanding WOs, Unit 1 had 11 corrective and general WOs and Unit 2 had 3 WO open. The Unit 1 work was generally to correct minor leakages in the system (oil, water, l l
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steam, or air leakage) and the Unit 2 work was to perform preventive maintenance for ;
the next outage. The work orders were e npeny prioritized and scheduled. Schedule !
implementation, work package plannino and maintenance performance for the July 12 Unit 1 turbine driven AFW pump planry J maintenance was poor (see Section M1.2).
The Units 1 and 2 AFW pump perfor.:.ance, as shown through inservice testing, had sufficient margin above design requirements. The pumps availability, tracked through l the maintenance rule, was greater than 99%
During field walkdowns, the inspectors confirmed valve position indication with drawings, normal system alignment, control room indications, and altamate shutdown panel
- indications. The inspectors identified minor discrepancies with the drawings, but valves
- were in the position needed for operability. The drawing discrepancies were captured i
through a CR and were being tracked by the system engineer. The inspectors also !
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identified that additional piping and a valve had been added to a drain for the primary
- plant domineralized water storage tank (water supply for the Unit 2 AFW system). The l- added piping and valve were not noted in the drawing or other reference material.
j Condition report 991583 and engineering memorandum 118191 were initiated to evaluate the affects of the ado!tional piping and valve on the seismic evaluation. The l piping and valve were removed. Additional minor housekeeping and equipment issues l- were identified and effectively addresse l The open engineering items for the AFW system (ems, temporary modifications, and basis for continue operation) were reviewed . The seven ems were properly prioritized
! and tracked. The system had no temporary modifications and had two minor basis for l continued operation documents. The UFSAR was reviewed and no deficiencies were l identified. One discrepancy between the operating manual and the UFSAR regarding l
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required Unit 2 AFW flow was identified. The system engineer was evaluating the issue at the end of this inspection perio l Conclusions The Unit 1 and 2 auxiliary feedwater systems were in overall good material condition as demonstrated by high maintenance rule system availability and low backlog of work orders Open engineering items were properly prioritized and tracke l s j
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i 11 M4' Maintenance Staff Knowledge and Performance M4.1 Ineffective Maintenance Work Control Delavs Corrective Maintenance J
. Insoection Scope (62701)
The inspectors noted that several safety related work activities extended past their j planned maintenance duration and that numerous work activities were dropped from the j daily work schedules during this work period. The inspectors reviewed records, i conducted interviews, and observed work activities to evaluate the cause of this observatio !
- . Observations and Fir @DSB While monitoring maintenance activities, the inspectors observed seven Unit 1 work activities that took significantly longer than planned or were canceled. In each case, the delay either increased plant risk or required operations personnel to change their
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' planned shift activity schedule and make additional plant manipulations. In addition,
- numerous scheduled work activities were dropped from the schedule at the daily
maintenance status meeting to manpower constraints. The inspectors determined that ,
several factors contributed to the poor work schedule implementation including operations _ and maintenance manpower constraints due to vacation schedules, poor communication between operations and maintenance personnel, untimely or incomplete i
, work package planning, and poor quality pre-job walkdowns. The poor work schedule l L implementation represented a weakness. Station personnel initiated condition reports to l address the individual deficiencies and improve the overall work schedule implementation performance. Examples of the deficient work activities are discussed j below.
l (1) ' On July 6, quench spray chemical injection pump QS-P-4C was taken out of I
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service for planned corrective maintenance. The work was scheduled for a 29- I hour duration, but actually required 65 hours7.523148e-4 days <br />0.0181 hours <br />1.074735e-4 weeks <br />2.47325e-5 months <br /> of a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> TS AOT. The delays l l- were associated with untimely work package planning. Parts availability verification and pre-job walkdowns were not performed prior to taking the component out of service for maintenance. The system fill and vent procedure, l necessary to support the PMT, was on hold pending incorporation of an OMC In addition, the pump rebuild had the potential to require an impeller clearance adjustment and re-alignment which would have significantly challenged the TS
. AOT. This was not factored into the schedule. Skillful work by the mechanics
- and exceptional support by performance engineers enabled QS-P-4C to be retumed to service prior to exceeding the TS AOT. CR's 991648,991649, 991667,' and 991668 were written to address these issue ' (2)
- - Both Unit 1 containment instrument air compressors (IA-C-1 A and IA-C-1B) failed in late June. This caused a total loss of containment instrument air and required operators to use abnormal operating procedures to cross connect station ai While monitoring repair activities, the inspectors identified that the work
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, 12-instructions were incomplete in that they did not contain sufficient instructions for the PMT. In addition containment entry to investigate the compressor failures was not timely. CR's 991570 and 991573 were written to address these issue (3) On July 11, turbine driven auxiliary feedwater pump FW-P-2 was taken out of service for planned corrective maintenance. This is a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> TS AOT which requires stat.on personnel to work around the clock to complete work and restore the component to service. Work orders were not planned on schedule and technicians did not perform a pre-job walkdown. During the work activity,
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technicians determined that parts for the intended exhaust boot repair were not available and the procedure for the planned overspeed linkage lube / inspect had expired. The exhaust boot repair was dropped from the schedule and the overspeed lube / inspect work was delayed. The planned PMT for two solonoid operated valves required revision and had to be re-performed. The total out-of-service time for the AFW turbine driven pump was 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> longer than the schedule and the exhaust boot repair was not complete (4). On Jur's 29, low head safety injection pump SI-P-1B was removed from service for a sc.neduied oil change. Late in the day, the inspectors questioned why the pump was still out of service for what had been a 5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> planned activity including PMT The NSS contacted maintenance personnel and coordinated restoration oithe pump. Poor communications between the maintenance and operations personnel resulted in an unnecessary 11 hour1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> extension of the TS limiting condition of operation duration. CR 991568 was written to address this issu Conclusions Poor maintenance planning resulted in work delays for several Unit 1 activities which either increased plant risk or unnecessarily required operations personnel to change their planned schedule and make additional plant manipulations. Several factors contributed to poor work schedule implementation including operations and me!ntenance manpower constraints, poor communication between operations and maintenance personnel, untimely or incomplete work package planning, and poor quality pre-job walkdowns. The poor work schedule implementation represented a weaknes M8 MisceManeous Maintenance issues M8.1 (Closed) LER 50-412/99-03. Containment Equipment Hatch Not Completely Closed During Refueling Operation a. _ Jnspection Scone (92700. 71750)
The inspectors performed an onsite review of the LER. The inspectors interviewed licensing engineers and maintenance engineers to evaluate the corrective actions and to determine the significance of the event.
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13 Qhservations and Findinas On March 12, a health physics technician identified that air was leaking by the Unit 2 containment equipment hatch. The unit was in a refueling outage and fuel movement was in progress. The NSS suspended fuel movement per TS 3.9.4 in response to the technician's report. Subsequent licensee interviews determined that a gap existed in the equipment hatch seal since March 11. The gap occurred when maintenance technicians removed chain hoists, which help support the equipment hatch, from servic Maintenance planners failed to identify the importance of the chain hoists during the planning of the preventive maintenance task. In addition, the maintenance technicians heard air leakage during the chain hoists clearance, but failed to recognize that the air leakage was a concem and was associated with their work. The inspectors determined that a questioning attitude by health physics technician identified this event. Corrective actions were reviewed and verified adequate to prevent recurrence. Based on postulated dose calculations performed, the potential safety significance of this event '
was small and well within design basis accident analysi TS 3.9.4 requires the equipment hatch to be closed during movement of fuel. Contrary to TS 3.9.4, on March 11-12, the equipment hatch was not completely closed. This Severity Level IV violation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy. (NCV 50-412/99-04-01).
cc Conclusions In March 1999, a health physics technician, using a questioning attitude, identified that the Unit 2 containment equipment hatch was not fully closed during fuel movemen Poor planning and failure by maintenance personnel to reccgnize the importance of chain hoists to support the equipment hatch was the root cause of the event. 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 99053 Ill. Enaineerina E1 Conduct of Engineering E1.1 Response to Emeroent Shutdown Issues Incoection Scooe (71707. 37551)
Several emergent issues were identified during the Unit 2 forced outage. The inspectors reviewed engineer assessment and disposition of the following issues:
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Low pressure in the AFW header (CR 991751)
Slow pressurizer power operated relief valve (PORV) stroke time (CR 591758)
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- Safety injection system check valve leakby (CR 991757)
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. The low pressure, due to check valve leakby, in the "B" AFW header was identified during Mode 3 (hot standby) normal operating tours. Operators appropriately declared the system inoperable per their operating procedure guidance. The system engineer, with design engineering support, effectively evaluated the issue and developed a detailed test plan. The AFW system performed satisfactorily during startu During surveillance testing, operators noted that the three pressurizer PORVs operated slower than the acceptance criteria of 1 second. Nuclear engineers worked well with the vendor to determine the impact of the slower closure. Several discrepancies were identified in the vendor's original design assumptions and the design of the valve These issues were captured in the corrective action system. A basis for continued operation was generated prior to startup and was supported by generic vendor informatio The safety injection system issue was identified when an operator heard a relief valve
' lifting during routine tours. System engineers determined that minor leakage was coming from the reactor coolant system through a series of check valves and a motor operated valve. Additional testing showed the leakage was well within technical specification requirements. Minor deficiencies associated with the check valve testing were discussed with system engineers and CR gg1834 was generate Conclusions
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System and design engineers provided good support and properly evaluated emergent Unit 2 shutdown issues such as check valve leakage in the safety injection and auxiliary feedwater system E2 Engineering Support of Facilities and Equipment E2.1 - Industry Ooeratina Exoerience Proaram Inspection scoos (37551. 62707. 71707)
The inspactors reviewed implementation of the station's Industry Operating Experience (IOE) program for the past 18 months to determine whether industry issues which may potentially effect Beaver Valley Power Station (BVPS) were properly identified, evaluated, and resolved. The inspectors evaluated disposition of industry issues emanating from outside sources as well as BVPS issues which held potential generic industry interes Observations and Findings The inspectors reviewed Safety and Licensing Administrative Manual (St.AM) Chapter 8,
" Industry Operating Experience (IOE) Program", Rev. 8. and determined that the t : program instruction was comprehensive. Licensing engineers, who administer the l
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program, were knowledgeable and forwarded applicable industry information to site personnel via computer networks in a timely manner. The CR system was properly used as a corrective action vehicle to track investigation and resolution of industry issues which potentially affected BVPS. Industry issues were typically evaluated and resolved in a timely manner. During the past year, the backlog of lOE reviews and action items was reduced from 12 months to 6 months of wor Based on interviews and field observations, the inspectors determined that system engineers and operations personnel understood the IOE program and actively used the ,
IOE database to obtain information related to their responsibilities. A specific strength !
was the operations departments' use of "just in time" training plans during pre-evolution i briefings for the Spring 1999 Unit 1 arid 2 outage l The inspectors reviewed the station's evaluations and associated actions for 12 NRC Information Notices (IN), five institute of Nuclear Power Operations (INPO) industry experience documents, and five vendor technical information letters. In all but two cases, the evaluations were thorough, technically sound, and clearly documented in IOE Positions Statements. Actions initiated to address the issues were clearly defined and properly tracked. Station personnel identified the same two deficiencies that the inspectors observed and initiated appropriate corrective actions. The inspectors noted )
that from 1990-1997 the station's evaluation and actions to address NRC IN 89-36,- l
" Excessive Temperature in Emergency Core Cooling System Piping Located Outside ;
Containment" were poor. Engineers corrected the monitoring program in 1998, and !
identified associated safety injection line check valve leakage in March 1999. This leakage was properly evaluated and the lines remained operable. During this inspection period, the inspectors noted that BVPS personnel had not effectively used industry information associated with marine fouling of safety related heat exchangers. This .
finding is documented in detail in NRC Inspection Report 50-334(412)/99-0 I Application of indestry information regarding electrical circuit breaker maintenance and testing was a strength. By using the industry lessons learned, material receipt inspections identified 12 deficient electrical circuit breakers during the last 15 month System engineers have maintained an active role with industry working groups on circuit breaker maintenance and testing guidance. Station personnel have routinely chared lOE information with the industry. BVPS has initiated 18 INPO lOE data base entr%s in the past 18 months (11 in the past 6 months). The BVPS initiated entries were clearly documented and the station received numerous calls from other nuclear power facilities which were similarly effecte c. Conclusions The Industry Operating Experience (IOE) program instruction was comprehensive and effectively managed and backlogs were reduced by 30 %. Engineers and operations personnel understood the IOE program and actively used the IOE databas Evaluations were typically thorough, technically sound, and clearly documented in IOE Positions Statements. Application of industry information regarding electrical circuit
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breaker maintenance and testing was a strength. IOE engineers actively communicated station issues which held potential generic industry interes E8 Miscellaneous Engineering issues (92700)
E (Closed) Licensee Event Reoort (LER) 50-334/99-03: Inadequate Basis for instrument Inaccuracies in Degraded Voltage Setpoints Lead to Technical Specification Noncompliance This issue was previously documented in NRC Integrated inspection Report Nos. 50-334(412)/99-01 Several setpoint values listed in Technical specification (TS) table 3.3-4 )
were nonconservative. Basis for continued operation (BCO) 1-98-012 was established !
in July 1998 to ensure emergency bus degraded voltage setpoints were maintained as !
required by design, until amendments to correct the nonconservative TS were approved l by the NRC. On six occasions between September 17 and October 28,1998, !
emergency bus degraded voltage relay trip setpoints were not maintained at or above the values specified in BCO 1-98-12. Failure to properly implement corrective actions, to correct this known condition adverse to quality, was a violation of 10 CFR 50, Appendix 4 B, Criterion XVI " Corrective Action." This failure constitutes a violation of minor significance and is not subject to formal enforcement action. The inspectors performed an onsite review of this LER and associated corrective actions. The LER adequately described the event and associated corrective actions were properly implemented or schedule i E8.2 (Closed) LER 50-412/99-04: Inadequate Basis for Seismic Instrument Setpoints and Calibration Led to Technical Specification Noncompliance The inspectors performed an onsite review of this LER. While implementing a design change to upgrade the Unit 2 seismic monitoring instrumentation, engineers identified that the calibration procedures did not ensure the accelerograph trigger and triaxial switch setpoints were maintained as specified in TG 3.3.3.3. The setpoints were implemented with a nominal acceptance band and in some instances the as-left setpoint was less conservative than permitted by TS. In addition, the instrument self test feature which was credited as the TS required calibration test, could not detect all of the sensor's potential failure and drift mechanisms. Therefore, the periodic seismic sensor calibration required by TS 4.3.3.3.1 was not properly performed. The seismic instruments were inoperable for greater than 30 days, due to the setpoint errors and incomplete calibration practices. This condition was not previously reported as required by TS 3.3.3.3. Failure to maintain seismic instrumentation as required by TS 3.3.3.3 and 4.3.3.3.1 constitutes a violation of minor significance and is not subject to formal enforcement actio The inspectors determined that the LER documented the event in appropriate detai The safety significance of the event was minimal. Corrective actions were either complete or scheduled with reasonable timeliness. Engineers worked closely with vendors' technical staffs and performed a comprehensive review of this event. The Unit 1 seismic instrumentation TS are written differently than those for Unit 2 and the licensee correctly determined that the event was not reportable for Unit 1. However, certain J
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corrective actions were necessary to ensure the Unit 1 seismic sensor setpoints were properly established and maintained. The inspectors independently verified that similar issues were properly addressed for Unit The inspectors noted that this was the third TS setpoint/ calibration range related LER issued within the past 6 months. While the LERs demonstrate improved questioning
- attitudes by station personnel, they also demonstrate that previous activities such as the 1997-1998 TS surveillance review project and the ongoing UFSAR verification project were not of sufficient depth to identify these TS non-compliances. The inspectors detcrmined that the safety significance of these three issues was low, and that station personnel demonstrated a heightened sensitivity to TS compliance. The inspectors concluded that programmatic corrective actions, including continued Engineering Safety Principles training were adequate to improve station personnel's awareness of TS requirement I E8.3 Resolution of Lona-Standina Enaineerina Problems Inspection Scope (IP 37550/929Q3)
As follow-up to the last Plant Performance Review (PPR), the NRC planned an inspection initiative to review the resolution status of long-standing system equipment design and performance problems. The inspectors reviewed the status of the Beaver Valley Power Station (BVPS) longstanding problem (LSP) resolution initiative developed in 1996 to resolve significant, long-standing, repetitive, and un-addressed equipment issues affecting the efficiency, reliability, and safety of plant operation Observations and Findinas in 1996, Duquesne Light Company (DLC) formed a Long-Standing Problem Review Team (LSPRT) at BVPS to identify and resolve LSPs. The LSPRT was staffed with Duquesne Light Company (DLC) engineers, and an outside engineering consulting fimi was retained to assist in forming a plan to identify and resolve the outstanding problem identification of Lono-Standina Problems A total of thirty-six problems were identified by the LSPRT. The problems were selected from a " top ten" list of equipment problems, " work-around" lists, maintenance history, and licensee event reports (LERs). These probierrs were evaluated to determine those that required corrective action to improve the efficiency, reliability, and safety of plant operations. The criterion for selection was that each problem was longstanding or repetitive, the problem was significant, no solution had been identified or implemented, .
and that the problem involved plant components, systems, or structures. Programmatic l issues were not considered under this progra Problem Prioritization All thirty-six problems were prioritized on the basis of actual importance to the plant (safety margin, plant performance, efficiency, reliability, risk, and achieving shorter
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outages), perceived relative value (improved operations, meeting NRC requirements),
- and the cost of any corrective action necessary. Members of the LSPRT individually ,
assessed each issue in accordance with the criteria, and the individual assessments
.. were combined to provide a priority list. From review of each individual assessment, the '
inspectors found no record that the prioritization assessments (made in 1996) were based solely on safety, risk, or core damage frequency estimates. The individual priorities were based on the experience and,iudgement of each assessor related to the
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importance of the problem to the plant. Safety was but one of the factors considere l The inspectors determined the prioritization approach was reasonable, i The thirty-six problems were placed in two groups by the LSPRT. The first group of problems met all the LSP selection criteria, and are listed in Table 1 in descending order of priority. The second group of problems is listed in Table 2, and did not meet all the LSP criteria, but were of sufficient significance to plant operation to warrant followu These were considered by the LSPRT not to require corrective action other than continued evaluation and monitoring of performance. The problems in Tab!e 2 are not listed in any order of priorit !
Table 1: Lono-Standina Eauioment Problems O - Open with Resolution in Progress C - Complete (SP Problem Tdle
, (O 1Q00) Unit 1 Cooling Tower Degradation (C 3Q98) Unit 1 Analog Rod Position Indication System (O 3Q99) Radiation Monitoring Equipment (C 1Q98) Control Room Habitability (C 4Q97) Screen Wash Pump Carryover (O 1QOO) CCR/CCP Relief Valve Test Failures l (O 3Q00) Unit 2 Fred-water Isolation Valve Accumulator Pressure i (C 2Q99) Units 1&2 Main Feed-water Pump & Motor Oil Leakage
! (O 3Q99) Automatic Rod Control System
! 1 (C 1Q99) Unit 2 Power Operated Relief Valve Piping i 1 (O 3Q99) Unit 2 Cooling Tower Thermal Performance 1 (C 1Q99) Unit 2 Boric Acid Blender Flow Control Valve 1 (O 3Q99) Unit 1 Reactor Coolant Pump Seal Leakoff 14 (O 4Q99) Unit 2 Un-interruptible Power Supply Fuse Fe!!ures 1 (C 2Q99) Unit 1 EDG Fuel Oil Transfer Pump Relief Vaive Leakage 1 (C 2Q99) Reach Rods for Manual Valves 1 (C 2Q99) General Relief Valve Failures 1 (C 2Q99) Goulds Pump Oil Leakage 1 (O4Q99) AnnunciatorSystems k
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. Table 2: Other Eouioment Problems O - Open with Resolution in Progress C - Complete -
NOH - Next Overhaul LSP, Problem Title l I (O 3Q00) Unit 2 Gland Steam Exhaust Filters (C 2Q99) Spurious Alarms Related to Electrical System Disturbances l (C 3Q97) Unit 2 RWST Freeze Protection / Standing Water (C 2Q98) River / Service Water System Chemistry Control
. (C 2Q97) Unit 1 Pump-house Summer Temperature Alarms (C 3Q97) Unit 1 Switchgear Chiller / River Water Support Systems (C 3Q98) Unit 2 Fuel Transfer System i (C 1Q97) Unit 1 Sampling System "Valcor" DC Solenoid Valves (O NOH) Unit 2 Primary Component Cooling Pump Damage J .' (O 3Q99) Westinghouse 7100/7300 Process Instrumentation (C 1Q97) Turbine Driven Auxiliary Feed Pump Solenoid Valves (C 1Q97) Unit 2 DC System Spikes '(O 2OOO) Safety Related Breakers
. (C 1Q97) Unit 2 Reactor Vessel Level Indication (O 3Q99) Unit 1 Containment Drain Tank isolation (C 1Q97) Unit 2 Containment Drain Pumps /Degassifier Pressure
- (C 1Q97) Unit 2 RCP Seal Leak-off Low Lona-Standina Problem Documentation The inspectors reviewed documentation related to the status of LSP resolution including the "Long-Standing Problem Review Team Summary Report," February 5,1997. This report provided guidance in problem identification, problem evaluation criteria, basis for prioritization, approach to problem review, and a clear summary for each of the thirty-six problems by the LSPRT. Quarterly reports continue to provide the status of each proble The inspectors reviewed the documentation for each of the thirty-six problems, in which the details of the problems, and course of resolution or projected plans are give Condition reports (CRs), design change requests (DCRs) and design change packages (DCPs) were identified in the documentation, in addition to the technical evaluation reports (TERs) and engineering memoranda (ems) located in the site files and available for revie y
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The inspectors found that the documentation of LSPs was generally satisfactory. The initial description of the thirty-six problems was comprehensive, implementation of problem resolution was duly documented with technical reviews and design change packages where appropriate, and the quarterly review of problem status provided for continuing oversight of problem resolutio Status of Problem Resolution The LSP inspection focused on the disposition of thirty-six problems since 1996. The latest status report, issued the second quarter of 1999, states that twenty-two problems had been resolved, and resolution of fourteen problems was currently in progress. Of the twenty-two problems that were resolved, ten were resolved through design changes; six were resolved through enhanced maintenance, alarm settings, equipment repair, condition monitoring, and changes in procedure; and six were declared resolved because subsequent observations and considerations of the component performance revealed no reoccurrence of the original problem. The fourteen issues currently in process of resolution are being resolved through design changes, equipment replacements, responses to technical evaluations and engineering memoranda, improved maintenance, and equipment overhaul ,
J The inspectors found that the long standing problems were appropriately efdressed by the licensee in accordance with their prioritized resolution plan. The inspectors acted that many of these problems existed since original plant startup, and that the systemized resolution of these problems only began in 1996 by the LSPRT. Since then 61 percent of the problems have been effectively resolved or eliminated because of non-recurrenc Reasonable action plans have been established for the problems still awaiting resolution and schedules for their completion are being monitored quarterly. The inspectors identified no operability issues and determined that the LSP items were being properly addresse Review of Problem Resolution with Enaineerina Personnel i
Using the second quarter 1999 LSP Status Report, the inspectors reviewed each of the i thirty-six problems with a member of the original LSPRT. The LSPRT member described each problem, its determined or perceived root cause, and the technical basis for its completed or planned resolution. The inspectors reviewed several of the problems in further detail with system engineers responsible for the problem area and found them to be knowledgeable of the problem and its resolutio Summary of Problem Resolution To-Date The prioritization system ranked issues for significance, based on the effect of the equipment problems on plant performance. Of the nineteen significant long-standing
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problems established by the LSPRT, ten were resolved by the licenses. Of these ten, five were resolved through specific corrective action, and five were removed from the LSP list because the problems did not recur. Of the five resolved problems, three will
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resolved, one is in a long-term structural replacement mode, three are in the process of l resolution, and three are in the process of determining the problem root caus j i
. Resolution of fmuteen unresolved poblems in Tables 1 and 2 has been delayed l because of the nature of construction (cooling tower), inability to determine the root cause of the problem (uninterruptible power system (UPS) fuse failures), time required to perform analyses, evaluations, and monitoring because of the technical difficulty of the .
problem ( reactor coolant pump (RCP) seal leak-off), difficulty in deciding which course 1 of action to take, and the cost of optimal resolutio Some of the LSPs were disqualified because of the absence of problem recurrence after selection as a LSP. The licensee indicated that some of these problems were inappropriately selected as LSPs (reach rods for manual valves, general relief valve failures, EDG fuel oil relief valve leakage, spurious alarms related to electrical system disturbances, and Gould pump leakage).
The inspectom found that the resolutions of unresolved problems of Table 2 are appropriately being implemente c. . Conclusions The Long-Standing Problem Review Team effectively selected, prioritized, and resolved long-standing equipment problems affecting the officiency, reliability, and safety of Beaver Valley Power Station plant operations. The completed resolutions to the long- I standing equipment problems were technically sound. The problems in process of resolution were being addressed in a careful and timely manner commensurate with their difficulty and safety significanc V. Manaaement Meetings X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on August 2,1999. The licensee acknowledged the findings presente The licensee did not indicate that any of the information presented at the exit meeting was propnetar .X2 Licensee Management Reorganization 1 On July 23,1999, Duquesne Light Company announced a reorganization of senior managers. Effective July 25, Mr. Lew W. Myers will assume the newly created position of Executive Vice President reporting to Mr. James E. Cross, President, Generation Group and Chief Nuclear Officer. Mr. Kevin L. Ostrowski, Division Vice President, Nuclear Operations Group and Plant Manager, will now report to Mr. Myers. Mr. Myers also retains the title of Senior Vice President of the First Energy Nuclear Operating
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Company, which has negotiated to acquire Beaver Valley Units 1 and 2 through an asset l transfer expected to conclude by December 1999. Mr. Myers previously served in senior nuclear management positions, which included Vice President of the Perry Nuclear Power Plant and Plant Manger at South Texas Project Unit I
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INSPECTION PROCEDURES USED lP 37550 Engineering IP 37551: Onsite Engineering i IP 61726: Surveillance Observation 4 IP 62707: Maintenance Observation IP 71707: Plant Operations IP 71750 . Plant Support IP 92700: Onsite Follow-up of Written Reports of Nonroutine Events at Power Reactor ;
Facilities 1
- IP 92901: Follow-up - Operations -
IP 92902: Follow-up - Maintenance IP 92903: Follow-up - Engineering IP 93702: Prompt Onsite Response to Events at Operating Power Reactors
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l ITEMS OPENED, CLOSED AND DISCUSSED l
Opened / Closed 50-0412/99-04-01' 'NCV Containment Equipment Hatch Not Completely Closed During Refueling Operations. Reference LER 50-412/99-03.-(Section M8.1)
- Closed 50-334/99-03 LER Inadequate Basis for instrument inaccuracies in Degraded Voltage Setpoints Lead to Technical Specification
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Noncompliance (Section E8.1)
50-412/99-03 LER Containment Equipment Hatch Not Completely Closed ;
. During Refueling Operations.' (Section M8.1) !
50-334/99-07 LER Manually initiated Reactor Trip During Pre-Planned ;
Shutdown (Section 08.1)
i l 50-412/99-04 LER Inadequate Basis for Seismic Instrument Setpoints and
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Calibration Led to Technical Specification Noncompliance (Section E8.2)
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LIST OF ACRONYMS USED j
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, 'AC E Air Conditioning .
ANS Assistant Nuclear Shift Supervisor !
AOT Allowed Outage Time APRif Analog Rod Position Indicator BCO- Basis for Continued Operation :
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CCR Closed Cooling Reactor CFR . Code of Federal Regulations
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