ML15244A729

Summary of 911112 Meeting W/Util in Rockville,Md Re Overall Status of Licensee Activities at DPC Plants W/Focus on Major Licensee Staff Reorganization

ML15244A729
Person / Time
Site:	Oconee, Mcguire, Catawba, McGuire
Issue date:	03/23/1992
From:	Martin R Office of Nuclear Reactor Regulation
To:	Office of Nuclear Reactor Regulation
References
NUDOCS 9204010264
Download: ML15244A729 (47)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555 March 23, 1992 Docket Nos. 50-413, 50-414 50-369, 50-370 50-269, 50-270, 50-287 LICENSE: Duke Power Company FACILITY: Catawba, Units 1 and 2 McGuire, Units 1 and 2 Oconee, Units 1, 2 and 3

SUMMARY

OF MEETING ON LICENSEE REORGANIZATION The meeting was initiated by the Duke Power Company (DPC or licensee) to brief NR( managegent on the overall status of licensee activities at DPC's three nuclear stations with particular focus on the major licensee staff reorganization recently announced. The meeting was held in Rockville, Maryland, on November 12, 1991, and was attended by senior NRC and licensee management.

Mr. R. Priory, Executive Vice President-Power Generation Group, and Mr. H.

Tucker, Senior Vice President-Nuclear Generation Department, discussed the basis for and the processes associated with the reorganization of the DPC staff. The reorganization is a major one which essentially decentralizes much of the nuclear operations for the three stations to their respective sites. provides on outline of the new organization down to a typical nuclear site functional organization. The basis for the reorganization was attributed to the desire to streamline and realign the ways of doing business inside the Power Group. The processes for determining the structure of the reorganization and the objectives of the reorganization are summarized in the handouts entitled "Power Group Restructuring: Steps To Excellence."

Several key aspects of the reorganization noted by the NRC staff were as follows:

Each site will have most of the resources needed to carry out its operations onsite. These activities will be managed under the newly created position of Site Vice President. DPC indicates that each site will be managed as a business utilizing a new group at each site to support this objective.

The Station Manager's position has been revised to focus on work planning, work execution, and work procedures.

Engineering combines resources from the previous Design Engineering and Construction Maintenance Division organizations. Numerous General Office engineering and technical activities, and personnel are being reassigned to the three nuclear sites.

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March 23, 1992

,Training activities will now report to site management.

Remaining in the General Office in Charlotte, North Carolina, will be the corporate Quality Verification Department, which includes the Nuclear Safety Review Board and the Nuclear Generation Department's Nuclear Services Division. Nuclear Services will address nuclear,

engineering, maintenance support, radiation protection and chemistry, and safety assurance issues common to all three sites.

The DPC also discussed its Integrated Safety Assessment (ISA) program. The program outline is provided in the Enclosure 3 handouts. The program was initiated in early 1990 and has been discussed with the NRC staff on several prior occasions. DPC stated that, to date, three formal assessments had been completed and that the process has value and will continue. Examples of the trend information provided to DPC management on performance of hardware, people management, and nuclear safety assessment are included in Enclosure 3 for each of the three sites.

The DPC also provided the information in Enclosure 4 on the status of precursor studies for the DPC plants. This topic was not discussed further in the meeting.

The NRC staff indicated that the meeting was very informative and expressed its appreciation for DPC's initiative in supporting the meeting.

/s/

Robert E. Martin, Senior Project Manager Project Directorate 11-3 Division of Reactor Projects - I/I Office of Nuclear Reactor Regulation

Enclosures:

As stated cc: See next page DISTRIBUTION:

DMatthews JWechselberger, EDO, 17G21 Loocket e

7 RMartin JTaylor, 17G21 NRC & Local PDR Wens JSniezek, 17G21 PDII-3 R/F TReed JRoe, 10H5 TMurley/FMiraglia, 12G18 LBerry EMcKenna, 10A19 JPartlow, 12G18 OGC, 15B18 SVarga Eordan MNBB3701 GLainas ACRS (10 yP-315 l

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LBerry hews DATE : /49 2

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SUM OF 11/12 MTG W/DPC

-2 Training activities will now report to site management.

Remaining in the General Office in Charlotte, North Carolina, will be the corporate Quality Verification Department, which includes the Nuclear Safety Review Board and the Nuclear Generation Department's Nuclear Services Division. Nuclear Services will address nuclear engineering, maintenance support, radiation protection and chemistry, and safety assurance issues common to all three sites.

The DPC also discussed its Integrated Safety Assessment (ISA) program. The program outline is provided in the Enclosure 3 handouts. The program was initiated in early 1990 and has been discussed with the NRC staff on several prior occasions. DPC stated that, to date, three formal assessments had been completed and that the process has value and will continue. Examples of the trend information provided to DPC management on performance of hardware, people management, and nuclear safety assessment are included in Enclosure 3 for each of the three sites.

The DPC also provided the information in Enclosure 4 on the status of precursor studies for the DPC plants. This topic was not discussed further in the meeting.

The NRC staff indicated that the meeting was very informative and expressed its appreciation for DPC's initiative in supporting the meeting.

Rob E,

Senior Project Manager Project Directorate 11-3 Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation

Enclosures:

As stated cc: See next page

Duke Power Company Catawba Nuclear Station McGuire Nuclear Station Oconee Nuclear Station cc:

Mr. R. C. Futrell Mr. Alan R. Herdt, Chief Regulatory Compliance Manager Project Branch #3 Duke Power Company U.S. Nuclear Regulatory Commission 4800 Concord Road 101 Marietta Street, NW, Suite 2900 York, South Carolina 29745 Atlanta, Georgia 30323 Mr. A.V. Carr, Esq.

North Carolina Electric Membership Duke Power Company Corp.

422 South Church Street P.O. Box 27306 Charlotte, North Carolina 28242-0001 Raleigh, North Carolina 27611 J. Michael McGarry, III, Esq.

Saluda River Electric Cooperative, Winston and Strawn Inc.

1400 L Street, N.W.

P.O. Box 929 Washington, D. C. 20005 Laurens, South Carolina 29360 North Carolina MPA-1 Senior Resident Inspector Suite 600 Route 2, Box 179N P.O. Box 29513 York, South Carolina 29745 Raleigh, North Carolina 27626-0513 Regional Administrator, Region II Mr. Frank Modrak U.S. Nuclear Regulatory Commission Project Manager, Mid-South Area 101 Marietta Street, NW, Suite 2900 ESSD Projects Atlanta, Georgia 30323 Westinghouse Electric Corp.

MNC West Tower - Bay 241 Mr. Heyward G. Shealy, Chief P.O. Box 355 Bureau of Radiological Health Pittsburgh, Pennsylvania 15230 South Carolina Dept. of Health and Environmental Control County Manager of York County 2600 Bull Street York County Courthouse Columbia, South Carolina 29201 York, South Carolina 29745 Ms. Karen E. Long Richard P. Wilson, Esq.

Assistant Attorney General Assistant Attorney General North Carolina Dept. of Justice S.C. Attorney General's Office P.O. Box 629 P.O. Box 11549 Raleigh, North Carolina 27602 Columbia, South Carolina 29211 Mr. R. L. Gill, Jr.

Piedmont Municipal Power Agency Licensing 121 Village Drive Duke Power Company Greer, South Carolina 29651 P.O. Box 1007 Charlotte, North Carolina 28201-1007

Duke Power Company Catawba Nuclear Station McGuire Nuclear Station Oconee Nuclear Station cc:

Dr. John M. Barry Mr. M. E. Patrick Mecklenburg County Compliance Dept. of Environmental Protection Duke Power Company 700 N. Tryon Street Oconee Nuclear Site Charlotte, North Carolina 28202 P.O. Box 1439 Seneca, South Carolina 29679 County Manager of Mecklenburg County 720 East Fourth Street Mr. Robert B. Borsum Charlotte, North Carolina 28202 Babcock & Wilcox Nuclear Power Division Mr. R. 0. Sharpe Suite 525 Compliance 1700 Rockville Pike Duke Power Company Rockville, Maryland 20852 McGuire Nuclear Site 12700 Hagers Ferry Road Manager, LIS Huntersville, North Carolina 28078-8985 NUS Corporation Washington, DC 20005 2650 McCormick Drive, 3 Floor Clearwater, Florida 34619-1035 Senior Resident Inspector c/o U.S. Nuclear Regulatory Commission Senior Resident Inspector 12700 Hagers Ferry Road U. S. Nuclear Regulatory Commission Huntersville, North Carolina 28078 Route 2, Box 610 Seneca, South Carolina 29678 Mr. Dayne H. Brown, Director Department of Environmental, Health and Natural Resources Division of Radiation Protection P.O. Box 27687 Raleigh, North Carolina 27611-7687 Office of Intergovernmental Relations 116 West Jones Street Raleigh, North Carolina 27603 County Supervisor of Oconee County Walhalla, South Carolina 29621

ENCLOSURE 1 Meeting Attendees Duke Power Company R. Priory, Executive VP-Power Generation Group H. Tucker, Senior VP-Nuclear Generation Dept.

M. Tuckman, VP-Catawba Site T. McMeekin, VP-McGuire Site J. Hampton, VP-Oconee Site L. Davison, Manager, Quality Verification D. Rehn, General Manager, Nuclear Services R. Futrell, Safety Assurance Nuclear Regulatory Commission 0J.

Taylor, Executive Director for Operations J. Sniezek, Deputy Executive Director for Operations J. Roe, Director, DLPQE S. Varga, Director, DRP I/11 G. Lainas, Assistant Director, RII Reactors E. McKenna, PDII-3 D. Matthews, Acting Deputy Director, DRIS R. Martin, PDII-3 L. Wiens, PDII-3 T. Reed, PDII-3

DUKE POWER COMPANY CORPORATE ORGANIZATION NOVEMBER 1, 1991 CHAIRMAN &

PRESIDENT W. S. LEE EXECUTIVE VP &

ASSIST. TO CHMN.

(THROUGH 1/31/91)

W. H. OWEN VICE CHAIR EXECUTIVE VP EXECUTIVE VP EXECUTIVE VP CORPORATE GROUP CUSTOMER GROUP POWER GENERATION GENERAL COUNSEL GROUP W. H. GRIGG W. A. COLEY R. B. PRIORY S. C. GRIFFITH

POWER GENERATION GROUP POWER GENERATION GROUP RICK PRIORY GENERATION STRATEGIC NUCLEAR QUALITY GENERATION FOSSIL AND HYDRO BUSINESS GENERATION VERIFICATION SERVICES GENERATION DEPARTMENT DEPARTMENT DEPARTMENT DEPARTMENT DEPARTMENT MIKE GREEN HAL TUCKER LARRY DAVISON JIM GROGAN MAURICE MCINTOSH DUKE/

GENERATION DUKE FLUOR HR ENGINEERING DANIEL DEPARTMENT

& SERVICES RON GREEN NEAL ALEXANDER JOHN NORRIS 9/25/91

GENERATION SERVICES DEPARTMENT GENERATION SERVICES DEPARTMENT JE GROGAN SECRETARY AC BARNETTE TECHNICAL ENVIRONMENTAI TRAINING SYSFEM BUSINESS AND HUMAN BAD CRAFT FINANCIL SERVICES SERVICES SERVICES

'SERVICES PLANNING RESOURCES CREEK GW GRIER JC LEATHERS IN BARR EM COUCH JE HURSI P BIRMINGHAM KR WEBBER

POWER GROUP RESTRUCTURING: "STEPS TO EXCELLENCE" JULY '91 - NOVEMBER '91 Signals for Change Strategic RT CDBR Plan Focus provement Area ecommendations Created Dinner Club Design Begin Organizational Aligning Organizational Evaluating Structure The Site Concept Process Evaluation Process Functions Success Criteri Reducing Barriers

• Consolidating

• Nuclear Excellence.

Management To Excellence Functions

• Shift to Demand Side Approval Objectives 00

• Aligning with

• Eliminating

• Financial Management Strategic Plan Process & System

• Environmental

• Using Our Human Redundancies Leadership Resources Strategically

• Reducing Levels

• Nuclear Refueling 9f24 and Increasing Spans Outage Board of Directors Management Approval

• Nuclear Modification

• Strategic & Business Planning 11/

• Cost Centers Implementation

• Dinner Club Agreement Rev. O 10/29/91

POWER GROUP RESTRUCTURING: "STEPS TO EXCELLENCE" BEYOND NOVEMBER '91 Managing And Driving Out Refining The Resource Process Stabilizing Organizational New Needs Steps The Transition Inefficiencies Organization Identification rganizatio Communicating the

• Defining Functions

• Making Structure

• Determining Required New Organization

& Processes "Tweaks" Resources:Workforce, Facilities, Equipment,

• Reducing Employee

• Re-engineering

• Determining: Missions, Commodities Objectives Uncertainty Work Processes Products, Services, and Systems Customers,Objectives

• Determining

• Building the "New" Technology Management Team

• Clarifying Roles, Requirements Responsibilities,

• Developing and Relationships

• Determining Skills Executing Detailed Needs/Development Transition Plans Continuous Imiprovemnent Cycle Rev. O 10/29/91

NUCLEAR GENERATION DEPARTMENT GENERAL MANAGER NUCLEAR SERVICES DAVE REHN NUCLEAR ENGINEERING ENGINEERING MAINTENANCE SUPPORT KEN CANADY DENNIS MURDOCK SEVERE ACCIDENT ANALYSIS ELECTRICAL ENGINEERING SAFETY ANALYSIS CIVIL ENGINEERING NUCLEAR DESIGN & REACTOR SUP'T MECHANICAL MAINTENANCE FUEL MANAGEMENT.

I&E MAINTENANCE CORE MECHANICS & T/H ANALYSIS MATERIALS PROCUREMENT SUPPORT RADIATION PROTECTION SAFETY ASSURANCE AND CHEMISTRY MIKE FUNDERBURKE MORRIS SAMPLE RADIATION DOSIMETRY & RECORDS NUCLEAR LICENSING SUPPORT RADIATION PROTECTION OPERATIONAL EVENT ANALYSIS RMC/RADWASTE PROCESSING EMERGENCY PLANNING NUCLEAR CHEMISTRY QA TECHNICAL SUPPORT OPERATIONS PERFORMANCE AND AUTOMATION SERVICES NEAL MCCRAW GENERATION SCHEDULING GENERATION RELIABILITY & OPERATING SUPPORT SYSTEM & COMPONENT PERFORMANCE THERMAL ANALYSIS & TESTING AUTOMATION SUPPORT

Typical Nuclear Site Organization Nuclear Site Officer Business Community Corporate Management Relations Communications

-.Cost Control

-Perf. Measures

-Business Plng.

Budgeting TrainingHuman Commodities &

Training Resoures Facilities Mgm't.

NcerSainEgneigSft suac Operations Employee Rel.

Procurement Design Eng'g.

Quality Assurance

-Maintenance Fitness For Duty Inventory Operations System Engg.

Safety Rev. Grp.

-Technical Svcs.

Indust. Hygiene Warehouse Mech. Mnt.

Reactor Eng'g.

Oper. Exper Pgm Employee Dev.

Safety & Med.

ToolEqpt. Mnt.

I&C PerfiTest Eng'g Modification Fire Protection

& Control

- Electrcal*

Maint. Eng.

Tech. Support.

Compensation Delivery/Issue

- Chemistry Projects merg. Ping Qualification Staffing K-Mac Contract Rad. Prot.

CMD Tech. Supp.

Security

-QA Insp. and

-Perf.

Test.

-Eng'g. Support*

Nuclear Access Testingi En gieein Major Projects Food Contract Site Fac. Mgmt.

Mod. Craft Doct. Control Payro l

RFO Craft Computerization ProcedureTeam QATech. Support Plng. & Sched.

Technical Support

- Operations Includes Transmission and baseload

- Limited Maint.-

support teas for large electrical

- Chemistry equipment (rotating, transforoers, Effective 11/1-91 Rad. Prot.

relays, etc.)

ENCLOSURE 3 DUKE/NRC MANAGEMENT MEETING NOVEMBER 12, 1991 AGENDA:

Introduction Duke Power Company Corporate Restructure Nuclear Generation Department Functional Description Quality Program Implementation a

Integrated Safety Assessment Historical Background First Half 1991 Assessment Results Trend Analysis Improvement Actions A

DUKE POWER COMPANY INTEGRATED SAFETY ASSESSMENT PROGRAM (ISAP)

A3

Initial Program Development Jan-Mar '90 NRC Communicates Concerns with Plant Performance High Number of Accident Sequence Precursor Events April '90 Self-Assessment Initiated June '90 Self-Assessment Completed June 18, 1990 Results Presented to NRC Management Al

Formal Program Development and Implementation

• July - Aug '90 Defined:

A) Scope B) Process C) Participants D) Responsibilities E) Frequency Formed Integrated Safety Assessment Group (ISAG)

• Sept '90 First Formal Assessment Completed

• Oct '91 Third One Completed A4

SAP Systematically and Independently Assesses Plant Performance From a Nuclear Safety and Operational Performance Perspective Provides a Focus Report to Senior Management Process is Trendworthy, ie.. Gives Compass Direction Conclusion Process Has Value, Will Continue A5

Catawba Nuclear Station HARDWARE PERFORMANCE EXCELLENT PERFORMANCE 3.5 -..

GOOD WITH OPPORTUNITY FOR IMPROVEMENT 2.5 2-NEEDS IMPROVEMENT 1.5 NEEDS SUBSTANTIi IMPROVEMENT 1

1ST 2ND 1ST 2ND 1ST HALF HALF HALF HALF HALF 1990 1990 1991 1991 1992 Analysis:

• Performance shows a slight decline e Basis

-. Rx trips involving equipment failure increased 1 to 2 R15A

Catawba Nuclear Station Actions to Improve Hardware Performance Criticial relays have been inspected on-line, and non-criticial relays are being inspected during outages R16

Catawba Nuclear Station PEOPLE PERFORMANCE 4

EXCELLENT PERFORMANCE 3.5 GOOD WITH OPPORTUNITY FOR IMPROVEMEN' 2.5 2-NEEDS IMPROVEMENT 1.5 NEEDS SUBSTANTI IMPROVEMENT 1ST 2ND 1ST 2ND 1ST HALF HALF HALF HALF HALF 1990 1990 1991 1991 1992 Analysis:

Performance shows a decline Basis 17 (59%) LER cause codes assigned involved inappropriate actions compared to 9 (43%) for previous assessment QA CSRG, PIR's noted increase in failure to follow procedures, improper actions, and inadequate work practices R17A

Catawba Nuclear Station Actions to Improve People Performance HPES root cause training provided to work groups in station e

Human Performance Excellence Team efforts Procedure format, content, use, and adherence Independent verification practices (Operations Focus Groups (RTT/CIA) formed to address operator performance

-- Grassroots involvement Highten awareness Recommendations for improvement

• n Increased training in other station groups relative to increase awareness of human performance problems I1S

g 0

Catawba Nuclear Station MANAGEMENT PERFORMANCE 4

EXCELLENT PERFORMANCE 3.5 GOOD WITH 3-OPPORTUNITY FOR IMPROVEMENT 2.5 2-NEEDS IMPROVEMENT 1.5 NEEDS SUBSTANTIAL IMPROVEMENT 1ST 2ND 1ST 2ND 1ST HALF HALF HALF HALF HALF 1990 1990 1991 1991 1992 Analysis:

Performance shows a decline Basis Recurring problems/NRC concerns involved configuration control R19A

Catawba Nuclear Station Actions to Improve Management Performance Implemented program of more detail review and investigation of events of lower significance Operations Management initiated Operations Focus Groups (RTT/CIA) to address configuration control problems R20

Catawba Nuclear Station NUCLEAR SAFETY ASSESSMENT 4

EXCELLENT PERFORMANCE 3.5 GOOD WITH 3-OPPORTUNITY FOR IMPROVEMENT 2.5 2

NEEDS IMPROVEMENT 1.5 NEEDS SUBSTANTIAL IMPROVEMENT 1

1ST 2ND 1ST 2ND 1ST HALF HALF HALF HALF HALF 1990 1990 1991 1991 1992 Analysis:

• Performance is good

• Decline not significant R21A

McGuire Nuclear Station HARDWARE PERFORMANCE EXCELLENT PERFORMANCE 3.5 3

GOOD WITH OPPORTUNITY FOR IMPROVEMENT 2.5

2.

NEEDS IMPROVEMENT 1.5 NEEDS SUBSTANTIAL IMPROVEMENT 1ST 2ND 1ST 2ND 1ST HALF HALF HALF HALF HALF 1990 1990 1991 1991 1992 Analysis:

• Performance remained good R8A

McGuire Nuclear Station PEOPLE PERFORMANCE EXCELLENT PERFORMANCE 3.5 GOOD WITH 3 -OPPORTUNITY FOR IMPROVEMENT 2.5 2-NEEDS IMPROVEMENT 1.5 NEEDS SUBSTANTIAL IMPROVEMENT 1

1ST 2ND 1ST 2ND 1ST HALF HALF HALF HALF HALF 1990 1990 1991 1991 1992 Analysis:

Performance shows a decline and needs improvement Basis Loss of off-site power event 2/11/91 16 (49%) LER cause codes assigned involved inappropriate actions compared to 4(14%) for previous assessment RSA

McGuire Nuclear Station Actions to Improve People Performance Station Manager personally held commitment sessions with all employees to clearly establish the expectations and standards relative to individual accountability and performance Providing Managing for Excellence Training which aims at quality work, constant improvement, and teamwork Implemented INPO's formal HPES program HPES root cause training provided to work groups in station, including Station Management Human Performance Excellence Team efforts Procedure format, content, use, and adherence Independent verfification practices RIO

McGuire Nuclear Station MANAGEMENT PERFORMANCE 4

EXCELLENT PERFORMANCE 3.5 GOOD WITH 3

OPPORTUNITY FOR IMPROVEMENT 2.5

2.

NEEDS IMPROVEMENT 1.5 NEEDS SUBSTANTIAL IMPROVEMENT 1

1ST 2ND 1ST 2ND 1ST HALF HALF HALF HALF HALF 1990 1990 1991 1991 1992 Analysis:

• Performance shows a decline Basis Loss of off-site power event issues R11A

McGuire Nuclear Station Actions to Improve Management Performance Multi-department task force reviewed administrative controls of switchyard activities and implemented recommendations (Affects Oconee and Catawba also)

Implemented program of more detail review and investigation of events of lower significance Implemented shutdown risk index for daily assessment and communication to management and outage coordinator R12

McGuire Nuclear Station NUCLEAR SAFETY ASSESSMENT 4

EXCELLENT PERFORMANCE 3.5 GOOD WITH 3 -OPPORTUNITY FOR IMPROVEMENT 2.5 2-NEEDS IMPROVEMENT 1.5 NEEDS SUBSTANTIAL IMPROVEMENT 1

1ST 2ND 1ST 2ND 1ST HALF HALF HALF HALF HALF 1990 1990 1991 1991 1992 Analysis:

Level of safety shows a decline Basis Loss of off-site power event 2/11/91 R13A

McGuire Nuclear Station Actions to Improve Nuclear Safety Performed risk assessment of hardware and scheduling of outage activities Actions previously identified under People and Management Categories Ri4

Oconee Nuclear Station HARDWARE PERFORMANCE 4

EXCELLENT PERFORMANCE 3.5 GOOD WITH 3 -OPPORTUNITY FOR IMPROVEMENT 2.5 2-NEEDS IMPROVEMENT 1.5.

NEEDS SUBSTANTIAL IMPROVEMENT 1

1ST 2ND 1ST 2ND 1ST HALF HALF HALF HALF HALF 1990 1990 1991 1991 1992 Analysis:

• Performance is good

• Decline not significant R1A

Oconee Nuclear Station PEOPLE PERFORMANCE 4-_

EXCELLENT PERFORMANCE 3.5 GOOD WITH 3-OPPORTUNITY FOR IMPROVEMENT 2.5 2-NEEDS IMPROVEMENT 1.5 NEEDS SUBSTANTIAL IMPROVEMENT 1

1ST 2ND 1ST 2ND 1ST HALF HALF HALF HALF HALF 1990 1990 1991 1991 1992 Analysis:

Performance shows a decline Basis Loss of RCS inventory event issues 3 NRC Level IV and 2 Level Ill violations involved human performance 3 Rx trips involved inappropriate actions compared to none for previous assessment 40% LER Root Causes Assigned involved inappropriate actions compared to none for previous assessment

Oconee Nuclear Station Actions to Improve People Performance p

Training provided on lessons learned from the loss of RCS inventory event Flange installation procedures Equipment/Component labeling Communications with control room s

Clarified operations personnel command and control expectations and work practices 0

Upgrading procedures affecting shutdown operations a

Reviewed independent verification practices HPES root cause training provided to work groups in station a

Human Performance Excellence Team efforts Procedure format content, use, and adherence Independent verification practices R3

Oconee Nuclear Station MANAGEMENT PERFORMANCE 4

EXCELLENT PERFORMANCE 3.5 GOOD WITH 3 -

OPPORTUNITY FOR IMPROVEMENT 2.5 2

NEEDS IMPROVEMENT 1.5 NEEDS SUBSTANTIAL IMPROVEMENT 1

1ST 2ND 1ST 2ND 1ST HALF HALF HALF HALF HALF 1990 1990 1991 1991 1992 Analysis:

Performance is good Decline not significant R4A

Oconee Nuclear Station Actions to Improve Management Performance

• Implemented program of more detail review and investigation of events of lower significance

• Implemented shutdown risk index for daily assessment and communication to management and outage coordinators R5

Oconee Nuclear Station NUCLEAR SAFETY ASSESSMENT EXCELLENT PERFORMANCE GOOD WITH 3

OPPORTUNITY FOR IMPROVEMENT 2.5 2

NEEDS IMPROVEMENT

1.

NEEDS SUBSTANTIAL IMPROVEMENT 1

1ST 2ND 1ST 2ND 1ST HALF HALF HALF HALF HALF 1990 1990 1991 1991 1992 Analysis:

• Level of safety shows a decline

• Basis

- Loss of RCS inventory event 3/8/91

- 2 NRC Level Ill violations Rx trips increased 2 to 4 LER's increased 8 to 15

Oconee Nuclear Station Actions to Improve Nuclear Safety Performed risk assessment of hardware and scheduling of outage activities Actions previously identified under People and Management Categories R7

ENCLOSURE 4 STATUS OF PRECURSOR STUDIES AT DUKE POWER COMPANY Backround Following the TMI-2 accident, the NRC began a program screening licensee event reports, estimating the conditional core damage probability (CCDP) of significant events, and publishing on an annual basis those events with CCDP's greater than 1OE-7 as precursor events.

This program-is called the Accident Sequence Precursor (ASP) program.

In this program the core damage potential of a significant event (such as a small loss-of-coolant accident or loss-of-offsite power) is estimated by considering the generic reliabilities of plant systems (such as the emergency core cooling.systems or the diesel generators) needed to safely contain the accident. Similarly, events comprising safety system failures pose a period of vulnerability for the plant in that if certain accidents occurred during that period, the ability to safely contain the accident would have been lost or significantly degraded. Therefore, these events are analyzed using probabilistic risk assessment techniques to determine the proximity of these events to an actual core damage condition. Typical nuclear power plants are believed to have a core damage probability of approximately 1OE-4, on an annual basis, even in the absence of the occurrence of any significant operational event. Therefore, operational events with CCDP's of lOE-5 or greater are of concern since they represent a potential reduction in the safety margin of the plant.

The NRC's ASP program is actually being conducted by the Oak Ridge National Laboratory and its subcontractor (SAIC).

In this program operational events with conditional core damage probabilities of 1OE-7 or greater are identified as precursor events and reported in the NRC publication, NUREG/CR-4674. (The screening criterion now is 1.OE-6.)

During the period 1984-1990, the NRC's ASP program listed a total of 25 events at the Duke plants.

For the most part, the NRC's ASP relies solely on the information in the LER and generic estimates of system reliabilities to compute the core damage potential. Often the analysts tend to make conservative assumptions on system capabilities and may not be aware of the actual system capabilities, alternate systems, or realistic operator response. Thus the estimated CCDP's generally tend to be conservative. Nevertheless, the precursor study results are apparently being used by the NRC in evaluating licensee and plant performance.

Duke Precursor Propram With the advancement of the PRA models for the Duke plants and the progress in the individual plant examination (IPE) studies and due to the NRC interest in the precursor events at Duke plants, a program for inhouse evaluation of the precursor events at Duke plants was initiated in 1990. This Duke precursor program is similar to the NRC ASP program but has the added flexibility to utilize the plant specific PRA models, data and system features.

In addition to the "at power" events considered in the NRC ASP program, the Duke study also considers significant shutdown events in a qualitative but

systematic way. A third distinguishing feature of the Duke precursor program is that it evaluates the trends in the occurrence frequency of all transient events and the maintenance unavailability performance of key plant systems.

Comparisons are made with the initiating event frequencies and maintenance unavailability values used in the PRA/IPE studies to identify any significant, adverse departures.

The precursor assessments are performed on a semi-annual basis by initially screening the LER data base and by evaluating the safety system unavailability data for the period.

The results of the precursor assessments are input into the integrated safety assessment program and communicated to management personnel.

The precursor assessments are also performed on selected LER events, and the results are reported as part of the LER safety evaluation.

Differences in the numerical values of the calculated core damage probabilities do occur between the Duke assessments and the NRC ASP results. This is because the Duke calculation would consider realistic operator responses, best estimate system capabilities and features such as the safe shutdown facility while the NRC ASP assessment is solely based on the LER information. For example, the 1990 McGuire D/G paint incident was treated as a total failure of the D/G system for 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> in the ASP assessment. Little credit was given for recovering the offsite power, should such an event occur and lead to a blackout condition.

The Duke assessment considered. that the as-found loading capability of the D/G was adequate for the loss of offsite power condition and that the period when both D/G were in the degraded condition was actually 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> instead of the 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> assumed in the NRC ASP study. Also, the capability to.restore offsite power was assessed to be of fair likelihood. Thus, the core damage probability was assessed to be 2.7E-4 in the NRC ASP study while the Duke precursor calculation gave a 3E-8 probability for the same event. Similar differences were found with regard to the 1989 McGuire steam generator tube rupture event and the containment spray heat exchanger gasket failure event. On the other hand, two Catawba events (one in 1989 and the other in 1990) involving the unavailability of a train of the auxiliary feedwater system and a diesel generator were assessed to be precursor events in the Duke precursor study, while the NRC ASP program did not identify them as such.

Results and Conclusions For the period 1984-1990, the NRC ASP program has identified 25 precursor events among the seven reactors in the Duke system. This represents approximately 0.6 events per reactor year. For the last two years (1989-1990), there were 3 precursor events, representing approximately 0.2 events per reactor year. These results are presented in the accompanying figure and indicate that precursor occurrence rate is decreasing in recent years.

A program to compute the core damage probabilities of significant operation events now exists inhouse in order to provide a realistic safety perspective of these precursor events.

A comparison of the precursor results based on the Duke precursor study and those from the NRC ASP program are presented in the following table.

The Duke results also portray an improving trend in the precursor occurrence.

DUKE PRECURSOR EVENT TRENDS ORNL Study 7

6 Cn) 1.-5 w 4 U 0 z

84 85 86 87 88 89 90 YEAR 1984 - 1990 Average = 0.63 events per reactor year 1989 - 1990 Average = 0.21 events per reactor year

RESULTS OF PRECURSOR STUDY AT DUKE PLANTS ORNL Study (NUREG-4674)

Duke Study Core Damage Core Damage YEAR Event Probability Event Probability 1984 1 Event 1985 8 Events No Duke calculations 1986 6 Events 1987 5 Events 1988 2 Events 1989 MNS SGTR Event 7.7E-4 MNS SGTR Event IE-6 MNS Cont. Spray Hx 1.6E-5 Shutdown event NSHX Gasket CNS Aux. Feed train 8E-7 unavailable 1990 MNS D/G Painting 2.7E-4 Not a significant pre-3E-8 cursor event

. CNS DG train unavail-2.E-6 ability 1991 Results not available MNS Switchyard event 1.E-4

November 12, 1990 MEMO TO FILE

Subject:

NUREG/CR-4674 Accident Sequence Precursor Quantification of McGuire Steam Generator Tube Rupture and Containment Spray Heat Exchanger Leak for 1989 File: MC-1535.00 The Severe Accident Analysis group has reviewed the results from NUREG/CR-4674 (Precursors to Potential Severe Core Damage Accidents:

1989 A Status Report) regarding two McGuire events.

This report quantified the conditional core damage (CCD) probability for the McGuire Unit 1 SGTR at 7.7E-04. It also estimated a CCD probability of 1.6E-05 for a hypothetical containment spray heat exchanger failure during a LOCA at McGuire Unit 2 based on a heat exchange failure during a shutdown overpressurization event.

It is understood that the purpose of this report is to highlight and rank significant operating events in the industry on a generic basis in order to focus attention on those events deemed important accident precursors.

However, it appears several assumptions used to quantify the significance of the two McGuire events were somewhat pessimistic and therefore over-estimate the significance of the events when compared with other operational incidents. In summary, (i) a review of SGTR thermal-hydraulic analyses have determined that safe stable states can be attained for many sequences classified as core melts in NUREG/CR-4674, and (ii) very little credit is given for the ability to isolate a NSHX leak during a LOCA even though several hours would be available for such action. Additional details concerning the assumptions used to quantify these events is provided below.

A. McGuire Unit 2 Containment Spray Heat Exchanger Leak Sequence The Severe Accident Analysis group has reviewed the analysis and assumptions used in NUREG/CR-4674 to quantify the McGuire Unit 2 Containment Spray Heat Exchanger (NSHX) failure event (LER 370/89-010).

While the potential scenario involving a gasket failure during a LOCA is valid, the assumptions used to quantify the conditional core damage estimate appear overly conservative and therefore over-estimate the significance of the potential event.

In particular, the probability of gasket failure and the estimated human error for leak isolation appear unjustifiably high. Listed below are comments and findings associated with the assumptions used to quantify the McGuire event.

NUREG/CR-4674 assumed an exposure period of 0.46 yr and a gasket failure probability of 0.10.

Both assumptions appear overly pessimistic considering:

1.

The NS system was operationally tested (including flow through the NSHX) three times since the gasket had been replaced without any failure or identified leakage.

2.

The NSHX gasket failure occurred when the system was incorrectly pressurized to approximately 300 psig during shutdown operations.

The system is designed for 230 psig and normal expected NSHX conditions are < 200 psig. No leaks were detected when the system was operationally tested under normal flow conditions.

.e 4

3.

Less severe gasket failure can be expected at < 200 psig compared with 300 psig. This could effect the potential leak rate should a failure occur at the normal lower pressure.

NUREG/CR-4674 assumed the failure to isolate the NSHX leak during a LOCA to be 0.34. This appears to be a high human error contribution considering:

1.

Annunciator alarms from Auxiliary building sumps would be expected in the control. room and Auxiliary building within several hours of the leak.

2.

Anyone transiting the Auxiliary building on level 716' or 733' would notice the large amount of water on the floor.

This water would be visible within minutes following a leak on the order of 1000 gpm.

3.

It would take approximately 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> before vital equipment would be in jeopardy (ND and NS pump motors).

It would take over 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> before enough water is diverted from the containment sump to fail recirculation flow.

.4.

ND and NS train flow indications could be used to identify the leak source. These indications are reviewed by procedure (EP/l/A/5000/2.3, Transfer To Cold Leg Recirculation)

5.

Control room operators, technical support center personnel, and the crisis management center personnel would be available to assess the leak consequences and propose recovery actions. There will be several hours available to accomplish isolation.

6.

The necessity for both trains of contatnment sprays does not exist several hours following the LOCA. Leak isolation actions should not be complicated by spray requirements.

7.

Isolation can be accomplished from the control room.

8.

By procedure (EP/1/A/5000/2.3), refilling of the FWST begins following recirculation switchover. This provides an alternate source of water to the four high pressure injection pumps (NI and NV) which can ultimately.provide core cooling without dependency on the ND pumps.

The above findings point out the advantage of obtaining utility assistance before attempting to quantify unique core melt sequences.

In summary, while the proposed event scenario is a valid one, the quantification estimate appears pessimistic.

B. McGuire Unit 1 Steam Generator Tube Rupture Sequence The.Severe Accident Analysis group has reviewed the analysis and assumptions used in NUREG/CR-4674 to quantify the McGuire Unit 1 Steam Generator Tube Rupture (SGTR) event (LER 369/89-004).

Modular Accident Analysis Program (MAAP) models developed for McGuire, as well as Westinghouse Owners Group Emergency Response Guidelines for SGTR, conclude that safe stable states can be attained for many of the

dominant sequences classified as core damage states in the NUREG study.

In particular, of the dominant sequences identified, only sequence #102 and #103 would be considered core damage end states if the ruptured generator could not be isolated. This requirement would change the core damage probability for these sequences by two orders of magnitude.

Thus, using NUREG/CR-4674 modeling probabilities, and success criteria based on plant specific MAAP models, the total conditional core damage probability for this event is estimated to be 7E-06.

Results from the McGuire PRA estimate a conditional core damage probability of 2E-07 for a SGTR event.

Provided below are the accident analysis results associated with two SGTR sequences of interest. The first sequence involves a SGTR with ECCS failure and an inability to depressurize the primary system through either pressurizer controls or through depressurization of the intact SGs.

The ruptured SG is isolated and auxiliary feedwater is available.

This sequence corresponds with NUREG/CR-4674 sequence #103.

MAAP results indicate the primary system and ruptured SG pressures equalize at approximately 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> with 1.7E5 lbs of water remaining in the primary system available for reflux cooling. This is a safe stable state. For this sequence to progress to core damage, the inability to isolate the ruptured generator would have to occur. Therefore, the core damage probability for this sequence will be reduced by two orders of magnitude.

The second sequence of interest involves a SGTR with a stuck open relief valve on the ruptured SG.

This sequence assumes that ECCS would function until FWST inventory was depleted. Auxiliary feedwater is available but the secondary PORVs are not available to depressurize the intact SGs.

MAAP results indicate that even 'without efforts to throttle safety injection flow, core uncovery would not occur until approximately 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br />. Core damage occurred at 25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br />. This analysis does not take credit for reflux cooling and is therefore overly conservative on the estimated time to core damage.

Also, if injection flow was throttled to match decay heat requirements,. core damage would not be expected before 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br />.

Thus, NUREG/CR-4674 sequence #102 would only be considered a core damage sequence if the ruptured SG was not isolated and even in this case core damage would be delayed beyond 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Sequence #101 which is significantly less severe than sequence #102 would progress to a state of pressure equalization prior to FWST depletion since auxiliary feedwater is available and secondary depressurization capability of the intact SGs exists.

This information was discussed with J. W. Minarick of SAIC (co-author of NUREG/CR-4674) on November 8, 1990 in order to relay our insights and concerns regarding the modeling of these two events.

B. E. Busby, Des 2

Engineer Nuclear Engineering Section cc:

K. S. Canady P. M. Abraham R.

L. White L. J. Azzarello L. J. Kachnik

McGuire Unit 1 Potential Inoperability of both DG's in Mode 1 (June 1990 event)

The Severe Accident Analysis group has reviewed the analysis and assumptions used in NUREG/CR-4674 to quantify the McGuire DG incident (LER 369/90-017). Several invalid assumptions were used in the Oak Ridge National Laboratory (ORNL) analysis:

1. The ORNL analysis assumes that both DG's were totally inoperable. In fact, DG 1 A was able to load to approximately 2800 KW on a second start attempt. Thus, DG 1A was functionally capable of carrying blackout loads with no LOCA present.

2. The ORNL analysis assumes that following a station blackout on Unit 1, all DC power will be lost within approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> due to battery depletion. Following battery depletion, core damage is assumed to occur due to a loss of turbine driven auxiliary feedwater pump control and loss of all primary and secondary monitoring indications. In fact, the DC busses at McGuire are shared, therefore a total loss of DC power would only occur if both DG's on the other unit also failed.

3. No credit is given for the Standby Shutdown Facility (SSF) which can operate independently of station power. The SSF contains a dedicated DG, standby makeup pump for NC pump seal cooling, and provides indications of essential plant parameters such as steam generator levels.

4. It does not appear that proper credit for recovering offsite power prior to core uncovery was taken.

Even if it is assumed that 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> following a station blackout that a loss of secondary side heat removal occurs, core uncovery would not be expected for another 2 to 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. Thus, approximately 4 to 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> would be available to recover AC power. The probability of not recovering offsite power within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is estimated to be on the order of 0.17 based on recent NSAC reports. Also, the DG's were locally recoverable as stated in the LER.

5. The time of vulnerability in which both DG's were assumed potentially inoperable is 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> not 99.6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

Based on the above arguments, Duke has estimated that the conditional core-damage probability for this event is approximately 3E-08 corresponding to a LOCA/LOOP event It does not appear appropriate to publish core-damage estimates without taking credit for actual plant system designs. Duke also compared this 1990 DG event with a comparable McGuire DG event analyzed by ORNL in 1987 (LER 369/87-030). Even though the accident scenarios were basically identical, the core damage quantifications varied by an order of magnitude even when considering the different vulnerability times.

It should be noted that several of these same invalid assumptions were used in analyzing the McGuire 1 emergency power incident of 9/8/87. Particularly, invalid assumptions concerning failure of the DC busses, and not taking credit for the SSF.