IR 05000272/1995013
| ML18101B001 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 09/13/1995 |
| From: | Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18101B000 | List: |
| References | |
| 50-272-95-13, 50-311-95-13, NUDOCS 9509180353 | |
| Download: ML18101B001 (89) | |
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Report No License No Licensee:
Facility:
Dates:
Inspectors:
Approved:
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
50-272/95-13 50-311/95-13 DPR-70 DPR-75 Public Service Electric and Gas Company P.O. Box 236 Hancocks Bridge, New Jersey 08038 Salem Nuclear Generating Station June 23, 1995 - August 12, 1995 C. S. Marschall, Senior Resident Inspector J. G. Schoppy, Resident Inspector T. H. Fish, Resident Inspector
~i~c~ty Inspector
Reactor Projects Section 2A Inspection Summary:
This inspection report documents inspections to assure public health and safety during day and back shift hours of station activities, including:
operations, radiological controls, maintenance, surveillances, security, engineering, technical support, safety assessment and quality verificatio The Executive Summary delineates the inspection findings and conclusion PDR ADOCK 0500027 G
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EXECUTIVE SUMMARY Salem Inspection Reports 50-272/95-13; 50-311/95-13 June 23, 1995 - August 12, 1995 OPERATIONS (Module 71707) The operations and maintenance staff thoroughly prepared for refueling activities. Operators effectively controlled and s~pervised the Unit 1 core off-load. Maintenance and operations staff identified a number of minor equipment problems on the fuel transfer system in preparation for core off-load. Operators ensured that maintenance personnel corrected the problems, allowing the fuel transfer system to function as designed, prior to beginning the core off-load. Refueling senior reactor operators (SROs), provided effective supervision of activities in containmen A Senior Nuclear Shift Supervisor (SNSS) initiative led to discovery of a conflict involving an Emergency Diesel Generator (EOG) surveillance overdue dat As a result, the SNSS prevented a missed surveillance, concurrent operation of two EDGs contrary to regulatory commitments, or a last minute rush to meet the surveillance requirement An operator's questioning attitude led to identification of inadequate emergency diesel generator surveillances. Operators promptly engaged engineering resources and made safe, appropriate interpretations of Technical Specification (TS) requirements to correct the surveillance procedure The operators used the updated procedures to demonstrate that the Salem Unit 1 and 2 EDGs remained operable. Throughout, operators remained appropriately focused on EOG operabilit MAINTENANCE/SURVEILLANCE (Modules 61726, 62703)
During the inspection period, the plant staff did not effectively control outage work for Salem Unit 1 in several case For example, several gallons of water escaped from the containment spray pumps onto the auxiliary building floor during system draining; the containment sump was inadvertently drained to the residual heat removal system, causing water hammer; and a redundant offsite power supply for Hope Creek was interrupted due to ineffective planning and communicatio These problems did not result in any damage to safety related component Further, the unit was.defueled which mitigated the safety significance of these maintenance problem Management counseled operators and continued efforts to identify, evaluate and correct weaknesses in work contro ENGINEERING (Module 71707)
The inspector noted an increasing trend of reactor coolant pump (RCP) seal failures since October 1994. Since engineering had not developed a root cause for the aggregate problem, the System Readiness Review Board (SRRB) recommended that a cross-disciplinary team fully investigate recent RCP seal malfunctions and determine the root cause prior to Unit 1 restar Engineers identified that installed Service Water (SW) bay sump pump motors challenged EOG operability due to possible EOG overloading under accident conditions. Operators immediately removed power to the sump pumps and insured i i
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(EXECUTIVE SUMMARY CONTINUED)
as a result of continuous manual operation of SW traveling screens and strainer The inspectors concluded that operators took appropriate immediate corrective action and planned a complete review of EOG ability to meet design basis requirements prior to plant restar PLANT SUPPORT (Module 71707)
Salem Radiation Protection staff continued to provide effective oversight of plant activities during the reporting perio In particular, the inspectors noted thorough oversight of Salem Unit I defueling activities and an increasing scope of other Salem Unit I outage activitie Inspectors noted that upgrades to the protected area assessment system improved the security force assessment capabilit SELF ASSESSMENT and QUALITY ASSURANCE (Module 71707)
During the reporting period, the Quality Assurance (QA) organization continued to demonstrate effective oversight of Salem performance. Three recent Salem and Hope Creek QA audits effectively contributed to the station's efforts to identify and resolve programmatic deficiencies. The recently completed audit of Salem In-Service Testing, identified several significant performance and programmatic problems with the licensee's establishment and implementation of the ISi progra This was viewed as a positive initiative by the license During the inspection period, plant staff identified and documented a significant number of degraded conditions. Plant staff initiated over 5000 Action Requests (ARs) during the report period indicating improved performance relative to identification and documentation of problems.
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SUMMARY OF OPERATIONS Unit I began the report period in Mode 5 (Cold Shutdown).
On July 25, 1995, the licensee commenced core off-load activities and completed the evolution on August The unit then entered a refueling outage that continued through the end of the inspection perio Operators maintained Unit 2 in Mode 5 (Cold Shutdown) for the duration of the perio.0 OPERATIONS The inspectors verified that Public Service Electric and Gas (PSE&G) operated the facilities safely and in conformance with regulatory requirements. The inspectors evaluated PSE&G's management control by direct observation of activities, tours of the facilities, interviews and discussions with personnel, independent verification of safety system status and Technical Specification compliance, and review of facility records. The inspectors performed normal and back-shift inspections, including 27 hours3.125e-4 days <br />0.0075 hours <br />4.464286e-5 weeks <br />1.02735e-5 months <br /> of deep back-shift inspection.1 Unit 1 Core Off-load The operations and maintenance staff thoroughly prepared for refueling activities. Operators effectively controlled and supervised the Unit I core off-loa Maintenance and operations staff identified a number of minor equipment problems on the fuel transfer system in preparation for core off-loa Operators ensured that maintenance personnel corrected the problems, prior to beginning the core off-loa Refueling senior reactor operators (SROs), in particular, provided effective supervision of activities in containmen For example, the refueling SRO noted that a Westinghouse manipulator operator moved a fuel assembly slightly in the wrong direction while the assembly remained partly inserted in the reactor vessel. Operators initiated a condition report (CR) to document that the fuel assembly might have sustained minor damage due to frictio Subsequent inspection revealed no indication of damag.2 Operator Attentiveness to Technical Specification Requirements Senior Nuclear Shift Supervisor (SNSS) initiative led to discovering a conflict in an EOG surveillance overdue dat As a result, he prevented a missed surveillance, concurrent operation of two EDGs contrary to regulatory commitments, or a last minute rush to meet the surveillance requirement On the night of August 10, the SNSS discovered that the IC EOG post overhaul 24-hour endurance run would very likely occur at the same time as the IA EOG monthly surveillance. The SNSS recognized this situation posed a problem in light of the Operations Department prior failure to avoid having more than one EDG synchronized to the grid at a time (documented in NRC Inspection Report
- 50-272&3II/95-07, section 3.2). The SNSS reviewed the weekly surveillance schedule to determine when IA was due and noted conflicting overdue dates for IA EDG, August 11 and August 14. The SNSS determined the last IA EDG surveillance occurred on July Technical Specifications (TS) required the next one within 31 days, plus a maximum grace period of seven days. This interval supported August I4. The SNSS subsequently coordinated the IA surveillance and the IC endurance test to assure that both EDGs would not be synchronized to the grid at the same tim The inspector noted that alert and conservative action by the SNSS prevented a potential repeat performance erro.3 Emergency Diesel Generator Testing An operator's questioning attitude led to identification of a problem involving emergency diesel generator (EDG) surveillances. Operators promptly engaged engineering resources and made safe, appropriate interpretations of Technical Specification (TS) requirements to correct the surveillance procedure The operators used the updated procedures to demonstrate that the Salem Unit I and 2 EDGs remained operable. Throughout, operators remained appropriately focused on EDG operabilit On July 9, 1995, an operator questioned the timing method used during a routine monthly emergency diesel generator surveillance. Technical Specification 4.8.1.I.2.a requires generator voltage within 3950 volts to 4580 volts inclusive, and frequency within 58.8 Hz to 61.2 Hz within 13 seconds after the start signal. Previously, operators timed the EDG start until frequency first reached the lower frequency limit (58.8 Hz).
Since the operator observed that, upon starting, the EDG increased to 58.8 Hz, then continued to increase in frequency above 61.2 Hz before settling within band, he did not stop timing the EDG until it had recovered to less than 61.2 H On July 10, operators noted that the 18-month EDG surveillance (TS 4.8.1.1.2.d.4) required voltage and frequency within the above limits within 13 seconds after the auto-start signal and that voltage and frequency remain within these limits during the test. The operators concluded that previous surveillances did not completely document compliance with TS 4.8.1.1.2. They declared all six EDGs inoperable and appropriately changed the Sl(2).0P-ST.DG-0001 through 0003, Diesel Generator Surveillance Test, procedures to require that "timing not stop until voltage and frequency return to less than or equal to 4580 volts and less than or equal to 61.2 Hz, or stabilizes within the band."
Plant staff reviewed previous surveillances and concluded that the EDGs had been operabl In addition, operators satisfactorily completed surveillances on all 6 EDGs (3 per unit) using the new timing metho.0 MAINTENANCE AND SURVEILLANCE MAINTENANCE The inspectors observed portions of the following safety-related maintenance to determine if the licensee conducted the activities in accordance with approved procedures, Technical Specifications, and appropriate industrial codes and standard The inspector observed portions of the following activities:
Work Order(WO) or Design Unit
_Change Package <DCPl Descriotion Salem I WO 950525097 II Switchgear supply fan expansion joint replacement Salem I WO 950713128 IC Emergency diesel generator (EOG) governor replacement Salem I WO 960318029 IC EOG air dryer repair Salem I OCP IEC-3387 IC EOG air receiver low pressure alarm Salem I WO 950422059 IC EOG I8 month inspection Salem 2 WO 950714086 Spent fuel pit heat exchanger leak repair The inspectors observed that the plant staff performed the maintenance effectively within the requirements of the station maintenance progra.2 Control of Outage Work During the inspection period, the plant staff did not effectively control outage work for Salem Unit I in several case For example, on August 7, as a result of ineffective control of draining the Containment Spray system, several gallons of water from within the system escaped through the pump casing vent, contaminating the pump and some of the surrounding floor spac On August 8, operators stopped draining the Unit I Residual Heat Removal systems (RHR) when Reactor Coolant System (RCS) level dropped unexpectedl After operators concluded that they should have expected the drop in RCS level, they resumed draining RH Later, operators opened an isolation valve to drain the Unit I containment sump into the drained RHR system, causing water hanuner to the RHR syste Salem staff defueled Unit I prior to the problems on August 7 and 8; as a result, the ineffective work control had no immediate safety significanc In addition, Salem operators opened a 500 KV breaker interrupting a redundant supply of power to Hope Creek during a Hope Creek EOG maintenance activity. The Salem operators opened the 500 KV breaker despite previous notification by Hope Creek of the EOG outag Although operators performed all of the activities within procedure guidelines, the activities represent a continued weakness in the ability to perform maintenance activities on systems or components without adversely impacting other plant system These problems did not result in significant damage to safety related components, and* the fact that Unit 1 was defueled, minimized the safety significance of these performance problem Management counseled operators and continued efforts to identify, evaluate, and correct weaknesses in work contro *
- 4 SURVEILLANCE The inspectors performed detailed technical procedure reviews, observed surveillances, and reviewed completed surveillance packages. The inspectors verified that plant staff did the surveillance tests in accordance with approved procedures, Technical Specifications and NRC regulation The inspector reviewed the following surveillances:
Unit Salem 1 Salem 1 Procedure N SC.OP-PT.DG-0001 Sl.OP-ST.DG-0002 Test EOG Barring Surveillance lB Diesel Generator Surveillance Test The inspectors observed that plant staff did the surveillances safely, effectively proving operability of the associated system.4 (Closed) Unresolved Item (50-272 and 311/93-15-01); Auxiliary Feedwater (AFW) Pump Operability During Power Ascension During a May 1993 Unit 2 startup, operators entered Mode 3 {Hot Standby)
without making the steam-driven AFW pump operable. Technical Specification (TS) 3.7.1.2 requires the pump to be operable in Modes 1, 2, and 3. Technical Specification 1.19, Table 1.1 defines Mode 3 as average reactor coolant temperature greater than or equal to 350 degrees However, TS surveillance 4.7.1.2.b.2 requires that operators demonstrate pump operability with steam generator pressure at least 680 psig {corresponding to an average coolant temperature of approximately 500 degrees). During the May 1993 startup, operators entered Mode 3 with the AFW pump clearly inoperable due to ongoing maintenance. Although the inspector recognized that operators could not perform the AFW surveillance prior to or upon first entering Mode 3, the inspector concluded that operators should have a reasonable expectation of AFW operabilit To resolve the issue the licensee revised procedure IOP-2, Cold Shutdown to Hot Standb The procedure revision included a step to verify the pump is functional prior to entering Mode 3 by establishing feedwater flow to each steam generator via the AFW pum Subsequently, when steam generator pressure reaches 680 psig, operators demonstrate pump operability by performing the TS surveillanc The inspector concluded the procedure revision established adequate means to insure a reasonable expectation of AFW pump operability upon entering Mode This item is close.0 ENGINEERING Reactor Coolant Pump Seal Failures The inspector noted an increasing trend of reactor coolant pump {RCP) seal failures since October 199 The inspector observed that the engineering department had not performed any assessment to determine the root cause or
- common facts relative to the RCP seal failure As part of the restart readiness review process, the System Readiness Review Board (SRRB) recommended a cross-disciplinary team fully investigate recent RCP seal malfunctions and determine the root cause prior to Unit 1 restar Since October 1994, maintenance personnel replaced three RCP seals {no. 22 RCP, no. 21 RCP, and no. 11 RCP) due to seal leak-off abnormalitie Engineering shipped some of the failed seals to Westinghuuse for analysis but had not determined a root cause nor initiated action to preclude recurrenc Recently operators initiated action requests (ARs) to investigate seal leak-off abnormalities noted in no. 21 RCP and no. 24 RC The inspector noted that RCP seals form part of the reactor coolant system (RCS) pressure boundary, and that seal failures imposed operational challenges to operators due to the potential for increased RCS leakag.2 Emergency Diesel Generator Loading Margin Action Request (AR) no. 950709084, dated July 9, 1995, identified the possibility that Salem had installed 14 horsepower (HP) Service Water (SW) bay sump pump motors rather than the specified 11.5 HP motors for Unit 1 and 1 HP motors for Salem Unit The AR concluded that 14 HP sump pump motors challenged EDG operability due to accident loading on the EDG Operators immediately removed power to the sump pumps and insured compensatory action in the event of a high sump alar The inspectors noted that engineering had previously identified concerns about EOG accident loading as a result of continuous manual operation of SW traveling screens and strainer As a part of routine inspection activities, the inspectors will follow the identified concerns for EDG loading, as well as the review of system readiness for other selected systems as the licensee's system readiness review process continue In the interim, the inspectors determined that the plant staff intends to address the SW sump pump concern prior to plant restar.0 PLANT SUPPORT Radiological Controls Salem Radiation Protection (RP) staff continued to provide effective oversight of plant activities during the reporting perio In particular, the inspectors noted thorough oversight of Salem Unit 1 defueling activities and other Salem Unit 1 outage activitie.2 Security The NRC verified PSE&G's conformance with the security program, including the adequacy of staffing, entry control, alarm stations, and physical boundarie Inspectors observed good performance by Security Department personnel in their conduct of routine activities.
On August 11, 1995, a regional security inspector met with licensee representatives to review the status of the upgrade of the protected area assessment system. The upgrade project included replacement of existing fixed
and variable assessment aids, alarm station monitors and assessment aid cable, and the installation of three additional assessment aid The inspector's review determined that the upgrade project was on schedule and that all fixed assessment aids, some variable assessment aids, and the alarm station monitors had been replaced. The completion of the upgrade, to include replacement of the remaining variable assessment aids and other improvements, is scheduled for December 199 The inspector observed that the images on the various assessment aids in the three alarm stations had improved in clarity and quality as a result of the upgrades completed to dat The NRC will continue to monitor the assessment upgrade program through completio.0 Safety Assessment and Quality Verification Self Assessment and Quality Verification During the reporting period, the Quality Assurance organization continued to demonstrate effective oversight of Salem performanc The inspectors reviewed two QA audit reports for previously completed audits with the following assessment:
QA audit 95-141, Salem Electrical Maintenance & Controls Audit, conducted from April 3 through May 4, resulted in eleven findings and fifteen observation The audit team identified ineffective corrective action, a fragmented preventive maintenance program, inadequate procedures, incomplete work packages, ineffective control of set point data, and use of uncontrolled work standards for Hagan Module maintenanc *
QA audit 95-130, Operations Audit, conducted May 5 through June 19, resulted in 29 findings and 41 observations for Salem and Hope Cree The audit team found that Salem did not effectively implement the guidance of Generic Letter 91-18 for operability of degraded condition The team found discrepancies with the tagging program and tagging verifications, determined that Salem did not resolve operator work around items in a timely manner, nor periodically reevaluate them to determine their aggregate impact on plant safet The audit team also found that a plant staff had not made a large number of revisions to the Operations staff office and control room copy of the Updated Final Safety Analysis Repor *
QA audit 95-012S In-Service Testing, Salem Generating Station, found that In-Service Testing (IST) methods did not meet ASME section XI or NRC requirement The audit team also found inadequate program documentation, ineffective scheduling and test performance, and inadequate control of test instrumentatio The QA audit reviewed the Salem IST relative to auxiliary feedwater, residual heat removal, service water, component cooling water, and emergency diesel generator system The results, including a stop work order for IST activities,
- indicated an apparent improvement in QA effectiveness as compared with performance in previous SALP period The inspector noted that the QA organization had not previously issued a Stop Work Order as a result of audit finding The inspector concluded that the Salem and Hope Creek Quality Assurance organizations were making effective contributions relative to the identification and resolution of deficiencie.2 Problem Identification and Corrective Action During the inspection period, plant staff identified and documented a significant number of degraded conditions. Teams of plant staff identified many of the degraded conditions during system walkdowns specifically intended to document degraded conditions for assessment and resolutio Plant staff initiated over 5000 Action Requests (ARs) during the report perio Based on the number and content of the Action Requests and Condition Reports, the inspectors concluded that apparent improvement is indicated relative to the licensee's performance in the identification and documentation of problem The following represent a small sampling of the documented conditions :
AR#
950621220 950706252 950709084 950712075 950718127 950719249 950720287 Description of identified problem The positive displacement charging pumps do not trip on a Safety Injection signal if offsite power remains available. This is contrary to the UFSAR chapter 1 Salem Unit 1 containment liner has indications of corrosion under the insulation at the 78 foot elevatio Installed 14.5 HP SW sump pumps (vs. design 11 HP) may cause EOG overloa Incomplete documentation of surveillance requirements for voltage and frequency leads to declaring all Unit 1 and 2 Emergency Diesel Generators inoperabl Formal calculations demonstrating that the control room emergency air condition system meets the General Design Criteria 19 dose criteria do not exis No. 22 RHR pump In-Service Testing (IST) error PORV accumulators may be undersized to insure RCS over pressure protectio Inappropriate range of pressure gauges used for Salem 1 and 2 IST testing of all Component Cooling pumps and three of four RHR pump '.
950721135 950724202 950810141
Technical Specification 5.2.2 (for both Salem Units)
states that the containment buildings are designed for a maximum internal air temperature of 271 degrees Fahrenhei The UFSAR, section 15.4.8.2 lists peak containment temperature for a steam line break of 351.3 degrees Fahrenhei The UFSAR, section 8.3.1.5, states the EDGs are designed to be ready to accept load within 10 seconds after a start signal. Section 8.3.1.5.1 states the EDGs have the capability to attain rated speed and voltage within 10 seconds after a start signa Technical Specification 4.8.1.11.2.D.3 states that the EDGs energize their vital buses with permanently connected loads within 13 second Lack of corrective action for 1994 repeated failures of EDG air start system relief valve.0 REVIEW OF REPORTS AND OPEN ITEMS The inspectors reviewed the following Licensee Event Reports (LERs) to determine whether the licensee took the corrective actions stated in the report, detect if the licensee responded to the events adequately, and ascertain if regulatory requirements and commitments were appropriately addressed:
Unit 1 Number LER 95-006 LER 95-008 LER 95-010 Event Date April 4, 1995 May 17, 1995 June 15, 1995 Description Entry into Technical Specification (TS) 3.0.3 due to inability of both units' control room emergency air conditioning systems to automatically actuat Controlled shutdown following entry into TS 3.0.3 due to inoperability of switchgear and penetration area ventilation syste Inoperability of both units'
residual heat removal (RHR) pumps for long~term flow requirements due to RHR flow instrument uncertainties.
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LER 95-011 February 22, 1988 Unit 2 LER 95-003 March 9, 1989
Inconsistency between WCAP-11634 analysis used for postulated steam line breaks outside containment and the updated final safety analysis repor Failure to perform type C local leak rate testing following piping modification to containment spray piping syste The inspectors determined that the LERs listed above were acceptable and considered the LERs close Unit 2 LER 95-004 June 7, 1995 Engineered safety features actuation (reactor trip) during Unit 2 controlled shutdown per TS 3. (see inspection report 95-10, section 2.1/2.4).
The inspectors previously addressed NRC concerns and regulatory requirements in the inspection report as note.1 Resident Exit Meeting The inspectors met with Mr. C. Warren and other PSE&G personnel periodically and at the end of the inspection report period to summarize the scope and findings of their inspection activitie Based on NRC Region I review and discussions with PSE&G, it was determined that this report does not contain information subject to 10 CFR 2 restriction.2 Specialist Entrance and Exit Meetings Date Cs)
7/31-8/4/95 8/7-11/95 Sybject Environmental Radiological Inspection Report N &311/95-15 50-272&311/95-16 Nuclear Business Unit Organizational Changes Reporting Inspector Peluso Noggle During the inspection period PSE&G initiated several personnel changes.
Effective June 30, Elbert (Bert) Simpson, formerly of Arizona Public Service, became Senior Vice President - Nuclear Engineerin Clay Warren, former plant general manager of Brunswick Nuclear Plant, became General Manager of Salem,
effective July 1 Effective July 24, Charles Smith, former station planning engineer at Hope Creek, became Manager - Nuclear Procurement and Materials Managemen Louis Storz, former vice president - nuclear generation at Niagara Mohawk Power Corporation, became Senior Vice President - Nuclear Operations, effective July 3.4 Management Meetings On August 10, 1995, an open management meeting was held with PSE&G to discuss the process the licensee was employing to determine the scope and extent of the outages for Salem 1 and The licensee's senior managers presented their plans for effecting performance improvemen The licensee's discussion slides are attached for informatio The licensee expects to be able to present fuller details on planned accomplishments in subsequent meetings with NR.5 Enforcement Conference An enforcement conference was held with the licensee on July 28, 1995 to discuss several violations identified in previous NRC inspection reports (50-272/311-94-32, 95-02, 95-07, and 95-10).
The licensee presentation materials are attached for information.
ATTACHMENT 1 NRC/PSE&G MEETING AUGUST 10, 1995 LIST OF PRINCIPAL ATTENDEES
NRC/PSE&G MEETING AUGUST 10, 1995 LIST OF PRINCIPLE ATTENDEES PSE&G SENIOR MANAGEMENT LEON ELIASON LOUIS (LOU) STORZ ELBERT (BERT) SIMPSON JOSEPH (JOE) HAGAN CLAY WARREN JEFFERY (JEFF) BENJAMIN MICHAEL (MIKE) RENCHECK PSE&G SUPPORT *
MARK REDDEMANN BRUCE PRESTON ERNIE HARKNESS ECATALFOMO RAJKOWSKI GREGSUEY
'.flKE METCALF
'.-:.RIC KATZMAN TERRY CELLMER FRANK THOMSON NRC TIM MARTIN JAMES LIEBERMAN JAMES LINVILLE JAMES MILHOAN JOHN WIIlTE WILLIAM DEAN JOHN STOLZ EUGENE KELLY LEONARD OLSHAN SCOTT BARBER ES MARSCHALL CHAEL CALLAHAN CHIEF NUCLEAR OFFICER &
PRESIDENT - NUCLEAR BUSINESS UNIT SENIOR VICE PRESIDENT - NUCLEAR OPERATIONS SENIOR VICE PRESIDENT - NUCLEAR ENGINEERING VICE PRESIDENT - NUCLEAR BUSINESS SUPPORT GENERAL MANAGER - SALEM OPERATIONS DIRECTOR - QA & NUCLEAR SAFETY REVIEW SYSTEM ENGINEERING MANAGER - SALEM GENERAL MANAGER - HOPE CREEK OPERATIONS MANAGER - SALEM ENGINEERING STATION PLANNING MANAGER - SALEM OPERATIONS MANAGER - SALEM MAINTENANCE MANAGER - CONTROLS (Acting)
CHEMISTRY MANAGER MAINTENANCE MANAGER - MECHANICAL RADIATION PROTECTION MANAGER STATION SELF-ASSESSMENT MANAGER MANAGER - NUCLEAR LICENSING & REGULATION REGIONAL ADMINISTRATOR - REGION I DIRECTOR, OFFICE OF ENFORCEMENT CHIEF - REACTOR PROJECTS BRANCH 3, DRP DEPUTY EXECUTIVE DIRECTOR FOR NUCLEAR REACTOR REGULATION, REGIONAL OPERATIONS & RESEARCH CHIEF, REACTOR PROJECTS SECTION 2A, DRP REGIONAL COORDINATOR, OEDO DIRECTOR, PROJECTS DIRECTORATE 1-2, NRR CHIEF, PLANT SYSTEMS SECTION, DRS LICENSING PROJECT MANAGER - SALEM PROJECT ENGINEER, REACTOR PROJECTS SECTION 2A SENIOR RESIDENT INSPECTOR - SALEM OFFICE OF CONGRESSIONAL AFFAIRS
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ATTACHMENT 2 NRC/PSE&G MEETING AUGUST 10, 1995 SLIDE PRESENTATION
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S~G Public Service fj Electric and Gas Company NUCLEAR BUSINESS UN~T SALEM REST ART PROCESS AUGUST 10, 1995 SALEM GENERATING STATION
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95mm2-1 SALEM REST ART PROCESS OPENING REMARKS
- Purpose of meeting
- Where we are today
- My vision for the character of operations at Salem
- How we will know when we are ready for restart
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SALEM REST ART PROCESS MEETING AGENDA Operations perspective Engineering performance issues Restart plan overview Work control improvements System readiness review program Independent oversight Concluding comments L. Storz E. Simpson C. Warren C. Warren M. Rencheck J. Benjamin L. Eliason
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SALEM REST ART PROCESS REST ART PERSPECTIVES Louis F. Storz, Senior Vice President -
Nuclear Operations
- Framework for restart and reliable operation
- Operational Leadership
- Improvement plan
- Aggressive problem solving
- Restart work scope
- Performance based results
- Vertical and horizontal communications
- Employee Accountability
- Managers
- Supervisors
- Hourly
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SALEM REST ART PROCESS RESTART PERSPECTIVES (CONT'D)
- Management expectations
- Quality supervision
- Improve training
- Fix the plant 95mm2-4
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SALEM REST ART PROCESS REST ART PLAN OVERVIEW Clay Warren, General Manager - Salem Operations
- Structure
- Management oversight
- Enforce higher standards and expectations
- Key processes and programs
- Restart work scope
- Restart readiness assessment
- Startup and power ascension plan
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SALEM REST ART PROCESS STRUCTURE
- New element of existing improvement plan
- Implementing proven restart approach
- Three major elements
- People
- Processes
- Hardware Objectives:
- Sustained, improved organizational performance
- Successful startup and sustained reliable operation
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95MM2-B SALEM REST ART PROCESS MANAGEMENT OVERSIGHT
- Line management ownership and accountability
- Vertical and horizontal communications
- Management Review Committee (MAC)
- Senior Management Oversight
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SALEM REST ART PROCESS ENFORCE HIGHER STANDARDS AND EXPECTATIONS
- Specific restart criteria to achieve goals
- Set restart performance indicator targets
- Complete and demonstrate effectiveness of near term action plans
- Improve questioning attitude
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- SALEM REST ART PROCESS IMPROVE PROCESSES AND PROGRAMS
- Integrated restart process and the ten near term action plans
- Measures of effectiveness established
- Near term action plans address Salem's performance weaknesses
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Conduct of operations Human performance Work control process Organizational self-assessment management Engineering Performance Reliable maintenance Outage performance Corrective Action Program Equipment Reliability Accredited operator training
- Effectiveness review of completed near term action plans l,*
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- SALEM RESTART PROCESS ESTABLISHMENT OF THE RESTART WORK SCOPE
- Comprehensive review, screening, and prioritization of existing and emergent
. issues
- Review of long-standing equipment problems
- Extensive system readiness reviews for 46 key systems
- Management Review Committee approval of the restart work scope 9511.41\\.42-11
SALEM RESTART SCHEDULE I I I
I dCT95 I NOV 95 I
- DEC*9.5>
AUG 95 SEP 95 I *.JAN 96 I FEB 96 I MAR 96 I APR 96 I I
SALEM UNIT 1 I
ALL UNIT 1 SYSTEMS SCREENED FOR RESTART r
I MRC REVIEW & ESTABLISH REST ART SCOPE I
PERFORM UNIT 1 OUTAGE'=RESTARf:WORK
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I FINAL UNIT 1 SYSTEM WALKDOWNS
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MRC READINESS ASSESSMENT I **=****=*:*TH:/"'// : *1 SENIOR MANAGEMENT REVIEW & APPROVE RESTART 1 *=.
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UNIT 1 STARTUP & POWER ASCENSION I I
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- .'*> I MRC REVIEW & ESTABLISH UNIT 2 SCOPE I
SALEM UNIT 2 I
I PERFORM UNIT 2 'OUTAGE RESTART WORK I
SENIOR MANAGEMENT REVIEW & APPROVE REST ART I I
UNIT 2 STARTUP & POWER ASCENSION I I
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..... I COMPLETE IMPACT PLAN DEVELOPMENT I MANAGEMENT OVERSIGHT I I
I COMPLETE UNIT 1 IMPACT PLAN ACTION ITEMS I
.. J DEVELOP UNIT 1 START UP & POWER ASCENSION PLAN r
I COMPLETE UNIT 2 IMPACT PLAN ACTION ITEMS I
DEVELOP UNIT 2 START UP & POWER' ASCENSION PLAN I I
NOTE: SCHEDULE IS SUBJECT TO ADJUSTMENT BASED ON WORK SCOPE DETERMINATION 11 ~
- System readiness assessment
- Department readiness assessment
- Operational readiness assessment
- Affirmations approved by Management Review Committee
- Independent assessments
- Restart recommendations made to senior management 95mm2-12
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SALEM REST ART PROCESS STARTUP AND POWER ASCENSION PLAN
- Startup Manager
- Shift management and support organization to augment the normal shift
- Dedicated maintenance and technical support to resolve emergent issues
- Training and briefings
- Management assessment hold points before power ascension
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SALEM REST ART PROCESS WORK CONTROL PROCESS IMPROVEMENTS Objectives
- Upgrade the work control program
- Reduce and manage backlogs
- Strengthen organizational support
- Upgrade support systems capability
- Performance indicators
- Total backlog
- Schedule adherence
- Age of work order
- Quality of planning
- Rework
- Indirect indicators 95mm2-14
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SALEM RESTART PROCESS SYSTEM READINESS REVIEW Mike Rencheck, Manager-System Engineering
- Enforce higher standards and expectations *
for system managers
- Assess and document system readiness
for restart
- Progress to date
- Long term results
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ATTACHMENT 3 PREDECISIONAL ENFORCEMENT CONFERENCE PUBLIC SERVICE ELECTRIC AND GAS COMPANY SALEM GENERATING STATION, UNITS 1 AND 2 JULY 28, 1995 LIST OF ATTENDEES U.S. NUCLEAR REGULATORY COMMISSION CNRCl G. Barber, Project Engineer, Division of Reactor Projects (DRP)
M. Callahan, Office of Congressional Affairs R. Cooper, Director, DRP.
T. Fish, Resident Inspector, Salem J. Gray, Office of Enforcement D. Holody, Enforcement Officer G. Kelly, Chief, Systems Section, Division of Reactor Safety (DRS)
J. Linville, Chief, Projects Branch No. 3, DRP K. Logan, NRC C. Marschall, Senior Resident Inspector T. Martin, Regional Administrator B. McDermott, Resident Inspector, Susquehanna L. Oshan, Project Manager, Office of Nuclear Reactor Regulation (NRR)
J. Schoppy, Resident Inspector, Salem K. Smith, Regional Attorney J. Stolz, Director, Project Directorate I-2, NRR J. White, Chief, Reactor Projects Section 2A, DRP J. Wiggins, Director, DRS PUBLIC SERVICE ELECTRIC AND GAS COMPANY (PSE&Gl J. Benjamin J. Hagan C. Lambert B. O'Grady E. Simpson C. Warren OTHERS D. Zannoni, NJ-BNE R. Pinney, NJ-BNE D. Vann, NJ-BNE R. Kankus, PECo Energy J. Javocha, Atlantic Electric K. Tosch, NJ-BNE P. Duca, Jr., Delmarva Power
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ATTACHMENT 4 PREDECISIONAL ENFORCEMENT CONFERENCE PUBLIC SERVICE ELECTRIC AND GAS COMPANY SALEM GENERATING STATION, UNITS 1 AND 2 JULY 28, 1995 SLIDE PRESENTATION
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PUBLIC SERVICE ELECTRIC & GAS ENFORCEMENT CONFERENCE JULY 28, 1995
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Introduction Management Perspectives Corrective Action Program Initiatives Discussion of Individual Violations
- Criterion V
POPS Issues Closing Remarks
AGENDA
J. Hagan C. Warren J. Benjamin B. O'Grady C. Lambert/
B. Simpson J. Hagan
- INTRODUCTION
Enforcement conference involves several apparent violation *
The broad implications of these examples -- the common causes -- are the central regulatory and management concer *
NBU presentation will address individual enforcement issues within the context of existing broad action Causal analyses have been conducted for individual violations, focusing on both individual and collective cause Corrective actions are being taken for each individual violatio Broad initiatives being taken to address common management performance, culture, and process issue *
As initiatives are implemented, similar examples may be identifie *
Improvements will take time, but will be achieved..
96EC-04 I
Vice President Buelneae Support Generlll MIMlager Salem Operations General Manager Hope Creek Operations NUCLEAR BUSINESS UNIT Senior Vk:9 Preeldent Nud_. Operallone Chief Nuclear Officer &
President-NBU Senior Vk:9 Presldatl Nuclear Englne9flng I
Dlr9CtQI'
Qually Aaauranc:&i'
Nucl_. Safely RQvlffW I
Director Human Reeourc:w
& Admlnlstrallon
7127/00
MANAGEMENT PERSPECTIVES Overriding Issue (IA 95-10): Problem Identification and Resolution
Willingness and ability to promptly and critically assess anomalous conditions. suspect component reliabilit Organizational proclivity to avoid prompt problem resolution, and prompt operability and corrective action decision-makin Approach to operability decisions biased to a positive determination without sufficient consideration of design base NBU Management Position:
NBU recognizes IR 95-10 concerns as a symptom of significant management and cultural weaknes ROOT CAUSES INAl>t'.QlJATE \\\\ORK PRAt.. Tl("t:S t'OR t:VAl.llAl ING <"ONIJll U>N~i INAOEQllA l E TRA ININt; llNCl.EAR EXPECT Al IONS
- "Al LURE TO SA TISY EXPECTATll>NS l"AllllRE TO Rt:("(X;Nlll:
Ni-"t:I> H)R ort:llABll.ITY tn:n:RMINA l ll>N t:XPt:l"TAllONS NOT t:NH)N INADEQllATl-: MANAGEMl::Nl OVERSIGlll <"llMMITMl::Nl rA.1t.1uu: TO ANAl.\\'/.t-:
l.A('K or Rt:OlllMt:o l\\NOWl..t:l><a:
INu*n:cnvE OPUlAHll.ITY u.ow nlARl~
- "All.I/RE 10 TAKE U:AUER."'lllP INADt:Q\\IATt: ORGANIJ.A TION INTERt'A<"E Tl/R,...AROl!NI> TIMt-HJR I.AH ANALYSES l!NTIMEl.Y l"ORNtTTIVt: A<"l ION IJSEC-0 I MANAGEMENT CORRECTIVE ACTIONS MANAGEMENT INITIATIVES ESTABLISH, COMMUNICATE, ENFORCE EXPECTATIONS ENSURE MANAGEMENT OVERSIGllT AND INTERVENTION EMl'llASIZE CONSERVATIVE APl'ROACll ENHANCE RESOLUTION PROCESS/E!ffABLIS,11 ACCOUNTABILITY EMPllASIZE TIMELY INTERVENTION MANAGEJ\\lENT OBJECTIVES ESTABLISH CULTURE OF ll\\ll'ROVEMENT ENSURE TIMEL\\'
PROBLEM RESOLUTION
MANAGEMENT PERSPECTIVES NBU Management Objectives:
Address culture to facilitate performance improvement *
Improve self-assessment capabilit *
Ensure timely problem identification, assessment, and resolutio *
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MANAGEMENT PERSPECTIVES Objective:
Address culture to facilitate performance improvement Initiatives:
(1)
Establish, communicate, and enforcP-expectation of rigorous complianc Actions:
(2)
Ensure management oversight and intervention throughout organization (multi-disciplined focus).
(3)
Emphasize conservative approach during problem assessment (~.
operability, root cause).
- Implemented management changes to improve culture, safety ethic, and conservative decision-making. (Complete)
Will adjust organizational areas of responsibility. (Future)
Assessing managers for appropriate leadership capability. (Ongoing)
Holding regular accountability meetings with senior management. (Ongoing)
Training of every manager and supervisor on expectations regarding Corrective Action Program. (Ongoing).
- Will utilize performance indicators to monitor performance. (Ongoing)
- MANAGEMENT PERSPECTIVES
_Objective:
Improve Self-Assessment Initiatives:
(1)
Instill a willingness to self-evaluat (2)
Improve problem assessment and root cause capabilit Actions:
Corrective actions for individual issues include root cause capability enhancement (Ongoing)
Developed methodology for driving self-assessment and improvement process. (Ongoing)
Developed appropriately focused performance indicators. (Ongoing)
Continuous improvements in performance indicators based on feedback. (Ongoing)
Will develop intrusive self-assessments to evaluate effectiveness of organization and performance improvement efforts. (Future)
Perform in-depth evaluation and assessment of equipment deficiencies as part of Unit 1 and Unit 2 restart initiatives. (Ongoing)
MANAGEMENT PERSPECTIVES Objective:
Timely and Quality Problem Resolution Initiatives:
(1)
Reduce threshold for reporting problem Actions:
(2)
Improve problem assessment and root cause determinatio (3)
Enhance problem resolution process and establish accountability fo1 proces (4)
Emphasize intervention to address issues promptl *
GM owns Corrective Action Progra *
Enhanced management expectations regarding problem resolution. (Complete)
Operability Determinations. (Complete)
Management oversight of completion time. (Ongoing)
Timely management intervention will be emphasized. (Ongoing)
Group established in Engineering to support Operations on operability determination (Complete)
In addition to SORC, General Managers (GMs) and station managers will review completed root cause evaluations. (Future)
GM and station managers will review Condition Reports on a daily basis. (Future)
Procedure already revised to reduce threshold. (Complete)
Corrective Action Program improvements being implemented -- J. Benjami 'J
CORRECTIVE ACTION PROGRAM INmATIVES Objective:
Ensure that potential deficiencies are evaluated and resolved in a complete and timely manne Initiatives:
Establish single point accountability for Corrective Action Program Oversight
Ensure a sound Corrective Action Program
Utilize personnel effectively
Monitor Process for Effectiveness
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CORRECTIVE ACTION PROGRAM INmA TIVES Establish Single Point Accountability:
Corrective Action Group established to oversee site-wide cs:mective action activitie (Complete)
Near Term Improvement Plan initiated. (Ongoing)
Implemented a graded approach to root cause analysis. (Complete)
Established and Implemented an Intervention Team to assist station departments with root cause assessment. (Complete)
Benchmarked several Corrective Action Programs. (Complete)
Developed and Implemented Consolidated Corrective Action Program. (Complete)
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CORRECTIVE-ACTION PROGRAM INmATIVES Ensure a Sound Program:
Corrective Action Program process consolidated and improved. (Complete)
Combined existing processe Low threshold progra Level 1, 2, and 3 issues reviewed by the Control Roo Formal process for Operability Determination Management expectations for timelines *
Root cause evaluations must be completed within 30 day *
Escalated management involvement for due date extensions.
"Old" process documents closed per existing procedures.
CORRECTIVE ACTION PROGRAM INmA llVES Utilizing Personnel Effectively:
Performed site-wide training on new corrective action process. (Complete)
Root cause training approach modified. (Ongoing)
Establishing Root Cause "specialists" in each department. (Ongoing)
Focal point for performing cause determinations (root cause or apparent cause).
Participate on Causal Factors analysi Provide insight for self-assessment effort *
Common cause trending and analysis *techniques being implemented. (Ongoing)
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CORRECTIVE ACTION PROGRAM INmA TIVES Proc~ss Monitoring:
Management involvement/oversigh Corrective Action Review Boar Daily overview of new and "due" Condition Reports (CRs).
Monthly Corrective Action Performance Repor Quarterly Causal Factor Analysi *
Performance Indicator Note: Appropriate performance criteria will be established for Salem restar Number and significance of new Condition Report Evaluation statu Process dynamic Backlog reduction (transition).
Evaluation completion time (in development).
Root cause quality (in development).
- Review of sample indicator *
- CORRECTIVE ACTION PROGRAM INITIATIVES Summary:
Changes to process and management oversight practices have been made to improve and further assure appropriate levels of Corrective Action Program performanc *
Appropriate performance criteria will be defined and utilized as part of the Salem restart process.
DISCUSSION OF INDIVIDUAL VIOLATIONS
. INDIVIDUAL ENFORCEMENT ISSUES CRITERION XVIN:
Reactor Head Vent Valve Limit Switches -- Safety Classification IA 95-02 (B.1)
Power Operated Relief Valve -- TS Action Statement IR 95-02 (B.2)
Reactor Head Vent Valve 2RC40 -- Test Failure IA 95-02 (B.3)
Oil Issues -- Degraded Conditions IA 95-07 (1-3)
Battery Charger -- Internal Inspection Work Order
IR 95-07 (4)
Pressurizer Code Safety Valves -- Set Point Tolerances LEA 95-05; IR 95-07 (5)
AHR Pump Minimum Recirculation Flow Valves -- Failure to Open IR95-10{A)
Switchgear Ventilation Supply Fan -- Evaluation of Operability IR 95-10 (B)
Containment Personnel Airlock -- Gasket Condition IR 95-10 (C)
CRITERION XVIN (continued)
INDIVIDUAL ENFORCEMENT ISSUES
EOG Jacket Water Cooling System -- Instrument Line Failures IR 95-10 (D)
Residual Heat Removal Discharge Valve RH 10 -- Impact Noises IR 95-10 (E)
Pressurizer Code Safety Valve 2PR66 -- Mispositioned Following Modification IR 95-02 (A)
PRESSURIZER OVERPRESSURE PROTECTION SYSTEM (POPS) ISSUES IR 94-32
Failure to Report Condition Outside Design Basis (50.72 and 50.73)
Reliance on Unapproved Code Case (50.60)
Failure to Perform Safety Evaluation (50.59)
Failure to Timely Correct (Criterion XVI)
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10 C.F.R. PART 50, APPENDIX 8, CRITERION V Pressurizer Code Safety Valve 2PR66 Issue:
During a modification to install a drain system for the Unit 2 Pressurizer Code Safety Valve Loop Seals, NBU did not adequately ensure that the drain valves were properly positioned prior to plant startup following installation. Specifically, valve 2PR66 was left closed throughout the operating cycle between May 1993 and October 1994. As a result, Unit 2 operated with the loop seals filled with wate NBU Position:
NBU agrees with the findin Root Causes:
Tagging Request Inquiry System (TRIS) Database backlog (6000 changes) was accepted:
not timely addresse *
Less than adequate turnover acceptance of the Design Change Package (DCP) by Operations. In particular:
The Operations DCP Coordinator only verified that the component was added to the TRIS Database and did not confirm that the component was added to the appropriate lineup The TRIS Coordinator did not create an auxiliary lineup according to procedur PR66 was not added to RC-MECH-001 lineup in a timely manne *
10 C.F.R. PART 50, APPENDIX B, CRITERION V Pressurizer Code Safety Valve 2PR66 Significant Corrective Actions:
TRIS backlog reduced to zero and being maintained at zer *
Design Change Packages from most recent unit 1 and Unit 2 Refueling Outages were reviewe *
Design Change Process to be revised to include final component positio *
Enhancements to be made to "Change Package Turnover" requirement Potential Consequences:
Engineering evaluation determined that no unacceptable restriction of pressure relief flow or pipe whip effects would have resulted from valve mispositionin Thermal hydraulic analysis performed to determine hydrodynamic effect of Power Operated Relief Valve (PORV) and safety valve actuatio Hydrodynamic loads combined with other load conditions (i.e.. deadweigh thermal, seismic) determined to be acceptabl Piping and supports operable above elevation 131' 4": functional below.
- PRESSURIZER. OVERPRESSURE PROTECTION SYSTEM (POPS) ISSUES POPS protects RCS from exceeding TS pressure/temperature (P1T) limits by opening two Power Operated Relief Valves (PORVs) during low temperature overpressure (L TOP) transients. POPS designed to meet single failure criterion -- either PORV wou:J have sufficient relief cap2city to limit peak pressure below Prr limi March 1993 Westinghouse Nuclear Safety Advisory Letter (NSAL) re: nonconse~vatisms in setpoint methodology for POP September 1993 Westingho_use provided Salem-specific bounding calculation results (Delta-P).
December 1993 PSE&G completed re-evaluation to address NSAL: peak transients could exceed Prr limit December 1993 Issue dispositioned by administratively limiting maximum number of Reactcr Coolant Pumps (RCPs) in service and increasing Pff limit by 10° o based on unapproved Code Case N-51 January 1994 System Engineer questions use of unapproved Code Case. indicates Westinghouse analyses acknowledges exceedance of Appendix G P1T curve April 1994 Discrepancy Evaluation Form (DEF) initiated to address NSAL issue without reliance on Code Case NS 14; no operability concern identifie May 1994 Second resolution of NSAL issue: Unit 1 TS P/T curve limit of 450 psig exceeded by 0.7: noted that RH3 and GOTHIC computer code would provide necessary margi September 1994 Problem Report (PR) by Mechanical Engineering: identified problem with relying on pressure "bubble".
October 1994 PR resolution, based on crediting existing administrative controls, revised POPS design basis transien November 1994 Incident Report by Nuclear Licensing and Regulation addressing error in revised POPS transient assumption: exceeds TS Prr limit Neither Westinghouse or industry had identified this aspect of the issu December 1994 LER 94-017-00 for Unit '*
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POPS ISSUES 1. 10 CFR 50.72 AND 50.73 (Reportability)
Issue:
Personnel became aware -- in December 1993 -- that the margins to TS PIT limits were reduced/lost; both Units were in an unanalyzed condition outside the Design Bases. Failure to report the condition is an apparent violation of 10 CFR 50. 72 and 50. 7 NBU Position:
NBU agrees with the findin The issue should have been recognized as reportable in December 199 Root Causes:
Lack of understanding of the regulatory significance (i.e. reportability implications) of the Westinghouse analysis result *
Failure to utilize formal processe *
Insufficient management monitoring of the proces *
Inadequate organizational interfac..
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POPS ISSUES 2. 10 CFR *so.so (USE OF AN UNAPPROVED CODE CASE)
Issue:
Reliance on an unapproved ASME Code Case N-514, without the required exemption. is an apparent violation of 1 O CFR 50.6 The Code Case was used in the December 1993 disposition; an exemption request was not submitted until December 199 NBU Position:
NBU agrees that reliance was inappropriately placed on the unapproved Code case in December 199 Root Causes:
Prior to January 25. 1994
Personnel performing the activity were inadequately trained for the tas *
Organizational interface was inadequate when Code Case was initially applie After January 25, 1994
Inadequate supervisor/management sensitivity to implement existing corrective action procedures and/or processe..
POPS ISSUES 3. 1 O CFR 50.59 (Safety Evaluations)
Issues:
Failure to perform a safety evaluation -- between October 1994 and December 1994 -- to determine if the change in the POPS design-basis transient had created an "unreviewed safety question" is an apparent violation of 10 CFR 50.5 NBU Position:
NBU agrees with the findin Root Causes:
The need for a safety evaluation was not recognized.
Personnel involved lacked objectivity -- they believed there was little safety significance to the issue and were focused on resolving the issue without consideration of associated regulatory requirements (i.e.. 50.59).
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POPS ISSUES 4. 10 CFR 50, APPENDIX 8, CRITERION XVI ffiMEL Y RESOLUTION)
Issue:
Failure to initiate timely or effective corrective actions to address the POPS setpoint issue is an apparent violation of Criterion XVI. PSE&G attempted to resolve the issue for over one year without entering the issue into either of the two existing quality systems for engineering discrepancies (the Incident Report system and the DEF process). The final resolution was not complete as of December 199 NBU Position:
NBU agrees with this finding. A DEF should have been initiated as early as March 1993. There were also many opportunities missed to initiate an Incident Repor Root Cause:
A lack of supervisor/management sensitivity to the need to implement existing program procedures, and processes, resulted in a failure to enter this issue into the Corrective Action Program *
POPS ISSUES SAFETY SIGNIACANCE Potential Consequences ultimately determined to be minimal, based on:
RH3 valve was available to limit peak pressure below Appendix G limit when POPS required to be in servic Code Case NS 14 was ultimately accepte Westinghouse NSAL safety significance evaluation (stress analysis) indicated that periods of operation outside Appendix G would create no problem in regards to vessel integrit *
Regulatory Significance derives from the broader implications: the failure to demonstrate rigorous adherence to established processes. to make prompt and conservative*
determinations on reportability and operability, and to efficiently deal with an engineering issue *in a timely fashio *
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POPS ISSUES CORRECTIVE ACTIONS The Corrective Action Program has been significantly improved.
Management has re-emphasized supervision's primary role to assess emerging issues objectively as opposed to helping develop a solutio Guidance has been provided to appropriate l;ngineering personnel on ASME Code applicatio Procedure and program commitment and compliance has been re-emphasized, especially in the area of "Corrective Action".
Personnel involved have received appropriate reinforcement on procedure compliance, responsibility for compliance with licensing commitments, and problem reportin Management has re-emphasized that 1 O CFR50.59 is applicable if revisions to calculations/evolutions alter either the design basis. basis of analysis. or conclusions in the FSA Lessons learned from these events will be disseminated_ to appropriate personne L_ __________
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POPS ISSUES ENGINEERING PERSPECTIVES
. Personnel and organizational assessments.
Regulatory process training.
Close licensing/engineering interface.
Sensitive issues awareness.
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CLOSING REMARKS
Corrective actions address:
Broad implications of issues -- Management and Corrective Action Progra Numerous Criterion XVI example *
PR66 issue consistent with Criterion XV *
Additional examples likely as result of ongoing effort *
Extensive corrective actions ongoin *
Culture and performance will change.
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APPENDIX - INDIVIDUAL CRITERION XVI ISSUES
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10 C.F.R. 50, APPENDIX B,.CRITERION xvr Reactor Head Vent Valve Limit Switches Issue:
NBU failed to timely evaluate and resolve a safety classification error related to reactor head vent valve limit switche NBU Position:
NBU agrees with the findin Root Causes:
Disposition of 1992 DEF
Inadequate work practices and supervisory methods for evaluating conditions adverse to quality. (IA was not issued and identification of non-safety related limit switches not pursued when 1992 DEF dispositioned.)
Inadequate communication and tracking program to confirm that corrective action was implemented. (DCPs were issued withAinclusion of revised limit switch classification.)
tOLJ,i:
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Disposition of 1994 DEF
Decision-making process was less than adequate. (The 1994 DEF was determined to not be an operability concern without seeking the appropriate facts and evidence. In addition, the priority determination used the function of the valve rather than the limit switch; therefore, information was not used correctly.)
10 C.F.R. 50, APPENDIX B, CRITERION XVI Reactor Head Vent Valve Limit Switches Significant Corrective Actions:
Outstanding DEFs are being reviewed for impact on operability prior to restar *
Previously resolved DEFs with follow-up actions are being reviewed for completion of committed action *
Tracking process established for DEFs which require follow-up actio *
DEF process has been incorporated into the NBU Corrective Action Progra *
Corrective Action Program has been significantly improve NAP-6 training and IMPACT Plan initiatives will address expectations re:
regulatory implication *
Non-safety related limit switches will be replaced prior to restart of Unit *
Non-safety related parts utilized in safety related applications are being evaluated for proper classificatio Potential Consequences:
Impact on RHVV --
Failure of limit switches in a manner that will impact the safety functions of the RHVV is not credibl Non-safety related switches are identical to safety-related switche Control power is ungrounded (requiring two faults to disable power].
Switches (reed type) are encapsulated in glas *
Impact on indication --
Common mode failure is not credible. Single failure will be indicated by having both open and close indication or not at all for a single valve.
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10 C.F.R. PART 50, APPENDIX B, CRITERION XVI Power Operated Relief Valve - TS Action Issue:
On February 24. 1995. Unit 1 operators placed control of a PORV in manual mode (rendering it inoperable), and failed to adhere to the Technical Specification (TS) 3.4.3 action statemen This performance error is similar to a violation of the same Technical Specification requirement involving Unit 2 on March 24, 1994. NBU's corrective actions for the earli~r event do not appear to have been effective in preventing recurrence of the recent performance deficienc NBU Position:
NBU agrees this was a performance deficienc Root Cause:
Failure of operations crews to satisfy expectations.
Narrow focus of previous corrective actions.
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10 C.F.R. PART 50, APPENDIX 8, CRITERION XVI Power Qpefated Relief Valve - TS Action Significant Corrective Actions:
Operating shift. as well as oncoming shift. counseled regarding expected level of performanc *
Modifications to Corrective Action Program will improve scope of corrective action effort *
Modifications to Technical Specification Action Tracking procedur Potential Consequences:
Failure to implement TS action statement in a timely manner did not have an adverse impact on the unit because:
Block valve did not have leakage at the tim A stuck open PORV is a low probability even Stuck open PORV is addressed in Emergency Operating Procedures (EOPs).
No impact of manually open PORV and open block valve on operator response if an event requiring the PORV had occurre Steam generator tube rupture is worst case applicable event and would not have been adversely affected by the as-found configuration.
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10 C.F.R. PART 50, APPENDIX B, CRITERION XVI Reactor Head Vent Valve 2RC40 - Test Failure Issue:
On July 6, 1994, safety related reactor head vent valve 2RC40 failed to separate (stoke open)
during testing whi!e Unit No. 2 was in cold shutdown. This failur::; was never documented and formally assessed relative to preventive maintenance. operability, actions to prevent recurrence, or generic implication NBU Position:
NBU agrees with the findin Root Cause:
Unacceptably high reporting threshol Inadequate management expectation Inadequate culture regarding evaluation, resolution, and documentation of event Significant Corrective Actions:
Corrective Action Program modifications will result in lower threshold, clearer management expectations, and documentation of event Expectations to be communicated and reinforced by management on a continual basis.
Assessment performed to ensure that similar component failures have been properly documented and assessed for extent of condition.
- 10 C.F.R. PART 50, APPENDIX B, CRITERION XVI Reactor Head Vent Valve 2RC40 - Test Failure Potential Consequences:
Failure occurred in Mode 5 when valves are not required: valve did not stroke open at higher temperature and pressure while still in Mode *
The Reactor Head Vent System is required in Modes 1-4 to vent off non-condensible gases subsequent to a LOCA during natural recirculatio Failure to open would preclude ventin Failure to close would result in additional inventory lost from the Reactor Coolant System (RCS) [to the Pressurizer Relief Tank (PRT) and eventually to the containment Emergency Core Cooling System (EGGS) sump].
NBU Probabilistic Risk Assessment (PRA) for loss of Head Vent System while in Mode 1 :
Failure to open - risk significance not readily calculated but judged to be low (valves are not credited in Chapter 15 analyses or in PRA).
Failure to close - risk significance considered negligibl *
10 C.F.R. PART-~. APPENDIX 8, CRITERION XVI Oil Issues Issues:
An oil sample laboratory report, dated August 4. 1994. recommended resampling and changing the oil on the No. 21 high-head safety injection pump based upon a ten-fold increase in wear concentration_
An oil. analysis, dated November 28, 1994, identified high wear particle concentration in the No. 22 high-head safety injection pump speed increaser oi A lab report, dated October 6, 1994, recommended resampling the No_ 23 Auxiliary Feed Auxiliary Feedwater (AFW) turbine lube oil due to a trace amount of water found and a marked increase in wear concentration particle NBU Position:
NBU agrees that these issues could have been more timely addresse Root Causes:
Expectations regarding individuals' responsibilities in the performance monitoring program were not enforce Turnaround time for lab analyses challenged the ability of the system engineer to make timely decisions_
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10 C.F.R. PART 50, APPENDIX B, CRITERION XVI 01i Issues Significant Corrective Actions:
Management's expectations have been clarified regarding system manager responsibilities in the performance monitoring progra *
The system manager concept has been implemented through reorganization, dedication, refocusing personnel, and individual reinforcement of individual system manager ownership, responsibility, and accountabilit *
NBU management is assessing options for improving the turnaround time for sample result Potential Consequences:
The underlying, specific technical issues had low potential for safety consequences because at no time was the equipment seriously degraded.
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10 C.F.R. PART--SO, APPENDIX B, CRITERION XVI Battery Charger - Internal Inspection Issue:
In May 1994, a System Engineer initiated a work request to inspect the 2A 1 28 VDC battery charger Ground Detection Circuit wiring. Tr1e request was initiated following a system walkdown that revealed that the Unit 1 chargers were configured differently than Unit 2 chargers. The work order to conduct the charger internal inspection was not performed until late 1995, and when conducted discovered that an incorrect configuration did exis NBU Position:
NBU agrees with the findin Root Cause:
Personnel Failur Failure to properly prioritize the corrective maintenance work orde Inadequate individual follow-through to ensure timely implementation of proces *
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10 C.F.R. PART50, APPENDIX 8, CRITERION XVI Battery Charger - Internal Inspection Significant Corrective Actions:
Assessments of whether similar ground detection circuitry wiring discrepancies exist will be completed by 8/15/9 *
The method for prioritization of maintenance work orders will be improved by 8/31/9 *
Appropriate disciplinary action was taken for failure to prioritiz *
Modifications to Corrective Action Program will better ensure adequacy of prioritization of similar work order Potential Consequences:
The internal ground detection circuit (improperly installed in 2A 1 VOC charger) did not affect the ability of the 28 voe system to perform its safety functio *
10 C.F.R. PART-50, APPENDIX B, CRITERION_XVI Pressurizer Code Safety Valves Issue:
Salem personnel, when informed by the vendor of out-of-tolerance Pressurizer Code Safety Valves, failed to initiate an Incident Report (IR), and therefore, the NBU did not initiate timely root cause or reportability evaluation NBU Position:
NBU agrees with the findin Root Cause:
Management expectations regarding when an IR was required (i.e.. reportability) were unclear/inadequately communicate System engineers did not recognize reportability implication *
10 C.F.R. PART-50, APPENDIX B, CRITERION XVI Pressurizer Code Safety Valves Significant Corrective Actions:
Personnel involved in failure to initiate I Rs were counsele *
The IMPACT Plan being implemented as. part of the restart effort contains actions to improve the definitions of roles, responsibilities, and results expected which will be used to hold individuals accountabl *
Training was conducted on new NAP-6; NAP-6 addresses operability and reportability reviews, as well as initiation of AR *
Lessons learned will be incorporated into quarterly operating experience feedback (OEF)
for Engineering support personnel (includes system managers and others).
Potential Consequences:
- Analyses which rely on PSV relief capability for mitigation meet all safety analysis criteria with/an assumed 3% setpoint toleranc *
These analyses were performed by Westinghouse for future UFSAR Chapter 15 changes.
10 C.F.R. PART-50, APPENDIX 8, CRITERION XVI RHR Pump Minimum Flow Recirculation Valves Issue:
From February 9, 1995 through June 7. 1995, plant staff did not timely and adec.iuately determine (and failed to correct) cause of failure of vales to open on low Residual Heat Removal (AHR) flo *
AHR was inoperable until June 7, 199 NBU Position:
NBU agrees with the findin *
Operating crews did not recognize the safety significance of valves' automatic open feature on January 26 and February 9, 199 *
Operability was not assessed in a timely manner from June 3, 1995 until the June 7 shutdown decisio Root Causes:
Less than adequate management oversight and implementation of Generic Letter 91-18 associated with:
Recognizing the need for an Operability Determination program and procedure Less than adequate training on Operability Determination Less than timely review of maintenance backlog related to Operability Determination *
The implementation of Operability Flow Charts was less than effective in improving Operability Determinations.
- 10 C.F.R. PART-50, APPENDIX B, CRITERION XVI RHR Pump Minimum Flow Recirculation Valves Significant Corrective Actions:
Operability Determination expectations reinforced by management and supervision.
Issuance of Operations Directive - 2, "Operability Determinations."
Training of Operations and Engineering personnel to reinforce expectations regarding application of Generic Letter 91-1 Ongoing reinforcement of operator awareness of Generic Letter 91-18 through requalification trainin Review of the entire maintenance backlog for additional "Operability DetE:rmination" issue Appropriate disciplinary actions.
Potential Consequences:
EOPs adequately address valve failure to both open or close. In particular:
Closed: Westinghouse analysis concluded that no RHR pump damage would be expected to occur for approximately 45 minutes in a deadheaded condition
EOPs address securing RHR pumps -- 45 minutes provides adequate time for this actio Open: minimum required ECCS flow met with valves open (WCAP 10325).
- 10 C.F.R. PART:SO, APPENDIX B, CRITERION XVI Switchgear Ventilation Supply Fan Issue:
From December 12, 1994, until May 16, 1995. plant staff failed to correct or determine the cause of the failure of the #12 safety-related switchgear supply fan. As a result, during this time. Unit 1 operated with a safety-related power system incapable of withstanding a single failur NBU Position:
NBU agrees with the findin Root Causes:
Operations personnel did not recognize that an operability assessment was required after the failure of the first fan (to address lack of standby fan).
- Neither Operations nor Technical Department took a leadership role in ensuring that the first fan was repaired in a timely manner.
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10 C.F.R. PART-50, APPENDIX B, CRITERION XVI Switchgear Veratilation Supply Fan Significant Corrective Actions:
Operations Directive, OD-02. was created to provide guidance to the SNSS/NSS for conducting Operability Determinations of Structures, Systems, and Components and for documenting review result The IMPACT Plan being implemented as part of" the restart effort contains actions to initiate a cultural change within the Operations Department (i.e., personnel must actively take a leadership role in pursuing needed repairs).
The system manager concept has been implemented through reorganization, dedication and refocusing of personnel, and reinforcement of individual system manager ownershi responsibility, and accountabilit Lessons learned will be incorporated into quarterly operating experience feedback (OEF)
by engineering personne Potential Consequences:
With certain actions and controls, the system was capable of maintaining required temperature Even with an active failure of the last operating SPAV supply fa coincident with a LOCA, Unit 1 could have been safely shutdown (assuming specified ambient outside temperatures, observed room temperatures, and using additional ventilation paths).
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PRA analysis also established acceptable risk for operation with both #12 and #13 fans inoperable for 5 days.
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10 C.F.R. PART--so, APPENDIX B, CRITERION XVI Containment Personnel Air1ock Gasket Issue:
On three separate occasions, Unit 1 staff failed to correct. determine cause, or prevent recurrence of the 100' elevation personnel airlock to pass its local leak rate test. From March, until May 8, 1995, the containment boundary was incapable of withstanding a single failure_
NBU Position:
NBU agrees with the Criterion XVI finding relative to timely corrective actio Howeve subsequent analysis shows the containment boundary was capable of withstanding a single failure and performing its intended functio Root Causes:
Practical root cause experience in the organization is limited.
Corrective action evaluations were not given appropriate priority by Maintenance organization.
- 10 C.F.R. PART 50, APPENDIX B, CRITERION XVI Containment Personnel Airlock Gasket Significant Corrective Actions:
Increased department management oversight of Corrective Action Program; better prioritization brought about by the significance levels established in NAP *
Established a core group of personnel to focus on root cause techniques to obtain experience on root cause evaluation As an interim step, added a utility loanee with root cause evaluation experience to the department staf *
Assessed proper lubrication requirement with vendo *
Reviewed other hatch openings that use this type gasket and determined that same conditions do not appl Potential Consequences:
Four seals on each door -- 2 inner, 2 oute Each door has two seal *
Airlock successfully passed 21 surveillance tests between March 6 and May 3 failure *
Total containment leakage remained below TS limi *
10 C.F.R. PART 50, APPENDIX B, CRITERION XVI EOG Jacket Water Cooling - Instrument Lines Issue:
From February 29, 1992, until June 7, 1995, Unit 1 staff failed to correctly determine the cause or take action to preclude recurrence of failures of instrument lines connected to the jacket water cooling system for the 1 B and 1 C Emergency Diesel Generators (EDGs).
NBU Position:
NBU agrees with the findin Root Causes:
The root cause of the piping nipple failure was an inadequate vibration tolerant design.
Failure mode was vibration induced fatigue crackin Contributing cause was a lack of specification of dimensions potentially critical to vibration tolerance on manufacturer documentatio *
The root cause associated with inadequate design modification implemented in 1986 was:
Failure to perform adequate post-modification testing to validate the effectiveness of the modificatio Lacking validation of the modification, failure to establish a conservative "qualified life" for the piping nipples.
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10 C.F.R. PART-50, APPENDIX B, CRITERION XVI EOG Jacket Water Cooling - Instrument Lines Root Causes (cont'd):.
The root causes associated with the inadequate corrective action following the 1992 1 C failure were:
Lack of required knowledge associated with prior failure Failure to perform any failure analysi Inappropriate corrective action process root cause determination threshol The root causes associated with the inadequate corrective action following the 1993 1 B failure were:
Personnel did not know or seek out all available information associated with prior failure *
Wrong assumptions were utilized in defining corrective action Corrective action to re-position the tubing supports was not identified in a timely manner and was not completed.
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10 C.F.R. PART*SO, APPENDIX B, CRITERION XVI EOG Jacket Water Cooling - Instrument Lines Significant Corrective Actions:
Upon discovery, compensatory actions were taken by Operations to assure m3ke up water was availabl Interim adjustment of 1 B and 1 C EOG piping was implemented to reduce the potential for resonanc Design changes have been identified and will be implemented for all EDGs prior to restar A vibration tolerance design review will be performed for all EDGs and peripheral equipmen Lessons learned from this event are in the process of being communicated to all appropriate Engineering personne *
Appropriate material will be incorporated into the maintenance and planning department training program Component Failure Analysis training has been conducted for approximately 67 individuals (design and system engineering personnel).
The Corrective Action Program has been significantly improved.
Potential Consequences:
The plant is designed to safely shutdown with two out of three EDGs. It is considered unlikely that failure of two EOG jacket water lines would occur within the period required to perform emergency repair for a first failure. Based on the failure mechanism, it is expected that sufficient time would be available for operators to detect the first jacket water leak to perform emergency repairs. Event recovery success is dependent upon the success of operator intervention to restore jacket water cooling to the failed EOG.
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10 C.F.R. PARTSO, APPENDIX B, CRITERION XVI RHR Discharge Valve RH10 - Impact Noise Issue:
F-rom July 1, 1992 until June 1 O. 1995, Salem staff failed to determine the cause of. correct. or prevent recurrence of impact noise from the interior of the No. 21 RHR discharge manual isolation valv NBU Position:
NBU agrees with the findin Root Causes:
Inadequate ManagemenUSupervisory Oversight Lack of engineering analysis of the physical condition of the valv Lack of discipline by system engineer regarding tracking, trending, and record keepin ',,
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10 C.F.R. PART-50, APPENDIX B, CRITERION XVI RHR Discharge Valve RH1U - Impact Noise Significant Corrective Actions:
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Valve will be disassembled and an engineering analysis will be written to document and validate the suspected cause of the impact noise *
System manager concept has been implemented through reorganization, dedicatio refocusing of personnel and reinforcement of individual system manager ownership, responsibility and accountabilit Potential Consequences:
Issue does not appear to impact operability.
Failure modes and effects for 21 RH10 were considered: in no case is the plant left with a loss of RH