ML043480034

Public Version of the January 2005 Director'S Quarterly Status Report

ML043480034
Person / Time
Issue date:	01/03/2005
From:	Office of Nuclear Reactor Regulation
To:	Barrett R, Black S, Boger B, Borsum B, Buckles R, Carpenter C, Chapman N, Stephanie Coffin, Dyer J, Emrit R, Fertel M, Foster J, Catherine Haney, Larhette R, Marsh L, Matthews D, Mckenna E, Merschoff E, Robinson N, Scott S, Beverly Sweeney, Watkins L Bechtel Power Corp, Institute of Nuclear Power Operations (INPO), Nebraska Public Power District (NPPD), NRC/EDO, Office of Nuclear Reactor Regulation, Office of Nuclear Regulatory Research, Nuclear Energy Institute, Scientech, US Dept of Energy (DOE)
Sweeney B NRC/NRR/DRIP/RPRP, 415-1029
References
Download: ML043480034 (133)

Text

DISTRIBUTION for NRR Director's Quarterly Status Report Central File RPRP R/F EMerschoff, EDO JEDyer, NRR DBMatthews, NRR LBMarsh, NRR BABoger, NRR RBarrett, NRR SBlack, NRR CCarpenter, NRR CHaney, NRR SCoffin, NRR EMMcKenna, NRR JFoster, NRR BJSweeney, NRR RCEmrit, RES Regional Administrators Mr. Marvin S. Fertel, Senior Vice President Ms. Nancy G. Chapman, SERCH Manager

& Chief Nuclear Officer Bechtel Power Corporation Nuclear Energy Institute 5275 Westview Drive 1776 I Street NW Frederick, MD 21703-8306 Suite 400 Washington, D.C. 20006-3708 Mr. R. P. LaRhette Mr. Rod Buckles Institute of Nuclear Power Operations Client Manager, LIS, NIIS and TRENDS 700 Galleria Parkway SCIENTECH, Inc.

Atlanta, GA 30339-5979 Suite 300 2650 McCormick Drive Mr. Lee Watkins Clearwater, Florida 33759-1049 Assistant Manager For High Level Waste U.S. DOE P.O. Box A Aiken, SC 29892 Mr. S. Scott Office of Nuclear Safety, DOE Century 21 Building (E-H72) 19901 Germantown Road Germantown, MD 20874-1290 Mr. Bob Borsum 1700 Rockville Pike, Suite 525 Rockville, MD 20852 Ms. Norena G. Robinson, Licensing Technician Nebraska Public Power District Cooper Nuclear Station -

P.O. Box 98 Brownsville, NE 68321 ADAMS ACCESSION NUMBER: ML043480034

DISTRIBUTION for NRR Director's Quarterly Status Report Central File RPRP R/F EMerschoff, EDO JEDyer, NRR DBMatthews, NRR LBMarsh, NRR BABoger, NRR RBarrett, NRR SBIack, NRR CCarpenter, NRR CHaney, NRR SCoffin, NRR EMMcKenna, NRR JFoster, NRR BJSweeney, NRR RCEmrit, RES Regional Administrators Mr. Marvin S. Fertel, Senior Vice President Ms. Nancy G. Chapman, SERCH Manager

& Chief Nuclear Officer Bechtel Power Corporation Nuclear Energy Institute 5275 Westview Drive 1776 I Street NW Frederick, MD 21703-8306 Suite 400 Washington, D.C. 20006-3708 Mr. R. P. LaRhette Mr. Rod Buckles Institute of Nuclear Power Operations Client Manager, LIS, NIIS and TRENDS 700 Galleria Parkway SCIENTECH, Inc.

Atlanta, GA 30339-5979 Suite 300 2650 McCormick Drive Mr. Lee Watkins Clearwater, Florida 33759-1049 Assistant Manager For High Level Waste U.S. DOE P.O. Box A Aiken, SC 29892 Mr. S. Scott Office of Nuclear Safety, DOE Century 21 Building (E-H72) 19901 Germantown Road Germantown, MD 20874-1290 Mr. Bob Borsum 1700 Rockville Pike, Suite 525 Rockville, MD 20852 Ms. Norena G. Robinson, Licensing Technician Nebraska Public Power District Cooper Nuclear Station P.O. Box 98 Brownsville, NE 68321 ADAMS ACCESSION NUMBER: ML043480034 ADAMS DOCUMENT TITLE: Public Version of January 2005 Director's Quarterly Status Report DOCUMENT NAME: DIST.WPD

DIRECTOR'S STATUS REPORT on GENERIC ACTIVITIES Action Plans Generic Communication and Compliance Activities JANUARY 2005 Office of Nuclear Reactor Regulation

INTRODUCTION The purpose of this report is to provide information about generic activities, including generic communications, under the cognizance of the Office of Nuclear Reactor Regulation. This report, which focuses on compliance activities, complements NUREG-0933, 'A Prioritization of Generic Safety Issues."

This report includes two attachments: 1) action plans, and 2) generic communications under development and other generic compliance activities. , "NRR Action Plans," includes generic or potentially generic issues of sufficient' complexity or scope that require substantial NRC staff resources. The issues covered by action plans include concerns identified through review of operating experience (e.g., Boiling Water Reactor Internals), and issues related to regulatory flexibility and improvements (e.g., Emergency Action Level Guidance Development). For each action plan, the report includes a description of the issue, key milestones, discussion of its regulatory significance, current status, and names of cognizant staff. , "Open Generic Communications and Compliance Activities," lists potential generic issues that are safety significant, require technical resolution, and possibly require generic communication or action. The attachment consists of two lists: 1) Open GCCAs and

2) GCCAs closed since the previous report. The generic communications listed in the attachment include bulletins, generic letters, regulatory issue summaries (which replace administrative letters), and information notices. Compliance activities listed in the attachment do not rise to the level of complexity that require an action plan, and a generic communication is not currently scheduled.

ATTACHMENT 1 NRR ACTION PLANS

TABLE OF CONTENTS DE OFFSITE POWER CONCERNS .......... .......................... 1 DAVIS-BESSE LESSONS LEARNED TASK FORCE RECOMMENDATIONS REGARDING ASSESSMENT OF BARRIER INTEGRITY REQUIREMENTS .......... .......................... 10 DIPM DAVIS-BESSE LESSONS LEARNED TASK FORCE RECOMMENDATIONS REGARDING INSPECTION, ASSESSMENT, AND PROJECT MANAGEMENT GUIDANCE ...... ................... 20 SIGNIFICANCE DETERMINATION PROCESS (SDP)

IMPROVEMENT . ............................................... 27 DLPM STEAM GENERATORS ............... .......................... 47 DAVIS-BESSE LESSONS LEARNED TASK FORCE RECOMMENDATIONS REGARDING STRESS CORROSION CRACKING ................................................... 68 DSSA PWR SUMP PERFORMANCE .......... .......................... 79 GENERIC SAFETY ISSUE (GSI) 189 - SUSCEPTIBILITY OF ICE CONDENSER AND MARK III CONTAINMENTS TO EARLY FAILURE FROM HYDROGEN COMBUSTION DURING A SEVERE ACCIDENT .................................................... 88 CONTROL ROOM HABITABILITY (INITIAL UPDATE) ..... ............ 97 FIRE PROTECTION PROGRAM (INITIAL UPDATE) ..... .............. 104

DRIP DAVIS-BESSE LESSONS LEARNED TASK FORCE RECOMMENDATIONS REGARDING OPERATING EXPERIENCE PROGRAM EFFECTIVENESS ..................... 116

OFFSITE POWER CONCERNS TAC No. MC3380 Last Update: 01/03/05 Lead Division: DE Supporting Divisions: DLPM, DSSA, and DIPM Supporting Office: RES GROUP ONE CONCERNS TO BE RESOLVED BY TEMPORARY INSTRUCTION 2515/156 Milestones Responsibility Estimated Completion Date

1. Issue tasking memorandum. ADPT 01/08/04 (C)

2. Establish interoffice coordination and areas of responsibility NRR/DLPM 01/16/04 (C) between NRR and RES.

3. Collect and prioritize grid issues for review. NRR/DE 01/30/04 (C)

4. Identify the applicable licensing basis assumptions that NRR/DE 01/30/04 (C) were evaluated in determining reasonable assurance of adequate protection of public health and safety for the offsite AC power requirements in GDC-17.

5. Short-term risk insights.

a. Develop the risk significance of the identified issues. NRR/DSSA 05/12/04 (C)

b. Draft of preliminary ASP results available (internal). RES/DRAA 02/06/04 (C)

c. Preliminary ASP analysis available for technical review RES/DRAA 02/27/04 (C)

(internaVexternal).

6. Using the licensing basis information and risk, determine NRR/DE 05/21/04 (C) and reconfirm if any immediate safety concerns exist that require the staff to take immediate action (or before summer 2004) and initiate action, as appropriate.

a. Issue RIS NRR/DIPM 04/15/04 (C)

b. Issue TI NRR/DIPM 04/29/04 (C)

c. Receipt of TI responses (key questions) Regions 06/01/04 (C)

d. Receipt of TI responses (remainder) Regions 06/30/04 (C)

7. Public Meeting with Industry. NRR/DLPM 03/05/04 (C)

NRR/DE 04/15/04 (C)

8. Regulatory Information Conference - Plenary Session. NRR/DLPM 03/10/04 (C) 1

Milestones Responsibility Estimated Completion Date

9. Using risk significance of each issue as a guide, develop an NRR/DE 07/27/04 (C) overall project strategy, evaluate the identified issues, and determine any corrective actions and the processes to attain implementation. Update the action plan as necessary.

10. Commission meeting on grid reliability issues. NRR/DLPM 05/10/04 (C)

NRR/DE 04/30/05 (T)

11. Establish interfaces with grid reliability organizations. NRR/DE on-going

12. Inform the Commission of the status of the Action Plan prior NRR/DLPM 05/10/04 (C) to the summer peak season. NRR/DE 08/06/04 (C)

13. Evaluate Station Blackout Implications

a. Using data from recent LOOP events, update the SBO RES/DRAA 11/16/04 (C)

LOOP frequency and duration(draft report for internal/external review).

b. Re-evaluate SBO risk (CDF) with updated SPAR RES/DRAA 01/28/05 (T) models for spectrum of plants (draft report for internaVexternal review).

c. Review SBO considerations and determine if regulatory NRR/DE/EEIB 06/01/05 (T) actions are needed.

14. Incorporate unresolved concerns into Group Three NRR/DE/EEIB 07/27/04 (C) concerns 2

GROUP TWO CONCERNS TO BE RESOLVED BY ACTIONS IDENTIFIED IN 2004 NERC AUDIT REPORTS Milestones Responsibility Estimated Completion Date

1. Receive NERC report. NRR/DE 06/30/04 (C)

2. Preliminary review of available reports to determine if all NRR/DE 07/02/04 (C) concerns have been addressed in the report.

3. Assess the information provided in the report to ascertain NRR/DE 07/09/04 (C) whether any concerns have been addressed.

4. Incorporated results into paper (See Activity 12, page 6) to NRR/DE 07/14/04 (C)

Commission.

5. Inform the Commission of the status of the Action Plan prior NRR/DE 08/06/04 (C) to the summer peak season.

6. Develop additional requests for information to address any NRR/DE 08/06/04 (C) short falls in the report (send to NERC).

7. Meet with NERC to discuss their response. NRR/DE 08/06/04 (C)

8. Re-assess any additional NERC input. NRR/DE 08/06/04 (C)

9. Develop Group Two disposition document if different from NRR/DE 08/06/04 (C) item 5.

10. Incorporate unresolved concerns into Group Three NRR/DE 12/22/04 (C) concerns, 3

GROUP THREE CONCERNS TO BE RESOLVED BY NRR LED REVIEW GROUPS Milestones Responsibility Estimated Completion Date

1. Assess input from TI responses and NERC report for NRR/DE 12/22/04 (C) possible resolution to any Group Three concerns.

2. Organize concerns by topic as described in Activity 9 for the NRR/DE 07/27/04 (C)

Group One concerns.

3. Determine staff to be included in review groups. NRR/DE 09/17/04 (C)

4. Determine NRR leads for review groups NRR/DE 08/02/04 (C)

5. Incorporate Group Two concerns not resolved in Group NRR/DE 08/06/04 (C)

One or Two assessments into Group Three concerns.

6. Develop schedule for review groups to review concerns. NRR/DE, RES, 01/30/05 (T)

(Stakeholders input)

7. Review groups obtain information necessary to address NRR/DE, RES, 12/22/04 (C) concerns. (Stakeholders input)

8. Review groups assess concerns. NRR/DE, RES, 02/28/05 (T)

(Stakeholders input)

9. Review group members develop regulatory position to NRR/DE, RES 03/31/05 (T) present to Commission.

10. Commission briefing NRR/DE 04/30/05 (T)

11. Final status of action plan on grid concerns to Commission. NRR/DE 06/30/05 (T) 4

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Description:==

The power blackout event on August 14, 2003, highlighted the fact that the Nation's electric grid is no longer being operated in the manner that it was considered when it was designed and constructed. An unreliable grid cannot ensure the availability of the offsite power system (preferred power supply), which is essential to ensure the safe operation of nuclear power plants (NPPs).

In December 2003, the NRC Chairman directed the NRC Executive Director of Operations to conduct a review of the issues raised in a report entitled "State of U.S. Power Grid from a Nuclear Power Plant Perspective." Following deterministic and risk evaluations, it was concluded for that for the following reasons, that there was certain urgency to address, before the Summer of 2004, plant operational readiness for the possibility that an event similar to the August 14, 2003, event occurs: (1) Long duration Loss of Offsite Power events are safety significant, (2) Risk increases when the plant's ability to cope with event is decreased due to online equipment outages, and (3) Grid is less reliable during the Summer period .

The plan describes the methods for resolving the concerns related to the loss of power to nuclear power plants. The plan will guide the reviews and assessments of the staff's efforts as we proceed on a resolution path of 48 concerns related to the reliability of offsite power to nuclear power plants. These concerns have been divided into three groups to be resolved.

To resolve Group One concerns, the staff developed a three pronged approach. First, the staff raised awareness of the concerns by developing and issuing a Regulatory Issue Summary (RIS) 2004-05 highlighting the significance of the concerns with the reliability of offsite power to nuclear power plants.

Second, the staff assessed the licensees readiness to manage any degraded or losses of offsite power through inspection and interview using Temporary Instruction TI 2515/156. Lastly, the staff maintained cognizance of conditions and events through the summer of 2004 and assessed findings to develop any proposals for long-term regulatory actions.

Concerns in Group Two may be addressed by a report to be published by North American Electric Reliability Council (NERC) assessing the grid operators implementation of the U.S. and Canada joint task force recommendations regarding the August 14, 2003, loss of electrical power outage. NERC's mission is to ensure that the bulk electric system in North America is reliable, adequate and secure. Since its formation in 1968, NERC has operated successfully as a voluntary organization, relying on reciprocity, peer pressure and the mutual self-interest of all those involved.

Group Three concerns are the remaining concerns not addressed by the other two approaches and also include those issues from two Staff Requirements Memoranda from the Commission. These concerns will be organized by topic and addressed by safety significance and the need for outside stakeholder input.

Historical

Background:

In 1992, the National Energy Policy Act (NEPA) encouraged competition in the electric power industry, which it defined as open generator access to the transmission system and statutory reforms to promote the wholesale of electricity. Built on that premise, in 1996, the Federal Energy Regulation Commission (FERC) issued its landmark Order 888 requiring open access to the Nation's electric power transmission system.

In 1997, the U.S. Nuclear Regulatory Commission (NRC) staff and representatives from the U.S.

Department of Energy (DOE), FERC, and the electric industry briefed the NRC on the issues related to electric grid reliability and utility restructuring. In response to the staff briefing, the NRC asked the staff to give greater urgency to ensuring that health and safety issues within the NRC's jurisdiction are addressed, particularly in reviewing the terms of the licensing basis and validating assumptions about grid reliability.

In 1998 and 1999, the NRC staff evaluated the impact of deregulation on the reliability of the electric grid.

This evaluation led to recommendations to confirm the licensing basis of the nuclear power plants and to reevaluate the under frequency protection trip settings.

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In 2000, the NRC asked Nuclear Energy Institute (NEI) and other industry representatives to take the initiative to address the adequacy of reliable offsite power to nuclear power plants. A key aspect of that initiative was the use of recommendations contained in a Significant Operating Experience Report (SOER) on the "Loss of Grid," which Institute of Nuclear Power Operations (INPO) issued in December 1999. In that report INPO called for establishment of communication protocols between the nuclear power plant operator and the grid operator.

In December 2003, the NRC Chairman directed the Office of the Executive Director of Operations (EDO) to conduct a review of the issues raised in a report entitled "State of U.S. Power Grid from a NPP Perspective." Following deterministic and risk evaluations, it was concluded that there was certain urgency to address, before the Summer of 2004, those significant issues manifested by the August 14, 2003, event.

Proposed Actions: The staff has identified 48 concerns with the reliability of offsite power to nuclear power plants that need to be resolved. These concerns have been divided into three groups to be resolved.

Group One contains 10 concerns that the staff has determined need to be addressed in the short-term.

Short-term is defined as the next potentially stressful electrical grid period (i.e., Summer 2004). To resolve Group One concerns the staff developed a three pronged approach. First, the staff raised awareness of the concerns by developing and issuing a Regulatory Issue Summary (RIS) 2004-05, "Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power," highlighting the significance of grid reliability with respect to the operability of the offsite power system for nuclear power plants.

Second, the staff assessed the licensees readiness to manage any degraded or losses of offsite power through inspections and interviews using Temporary Instruction (TI) 2515/156, "Offsite Power System Operational Readiness." Lastly, the staff monitored and reviewed conditions and events through the summer of 2004 and assessed any finding to develop any proposals for long-term regulatory actions.

Group Two has 21 concerns most of which are beyond the statutory authority of the NRC and fall within FERC's and NERC's purview. These concerns may be addressed by a report to be published by NERC assessing the grid operators implementation of the U.S. and Canada joint task force recommendations regarding the August 14, 2003, loss of electrical power outage. The staff will assess the information in this report and other NERC corrective actions to ascertain whether the Group Two concerns have been addressed by NERC.

Group Three has 17 remaining concerns not addressed by the other two approaches. These concerns cannot be addressed without further research and evaluation. Group Three concerns will be organized by topic and addressed by safety significance and the need for outside stakeholder input. An NRC review group will be assembled with the appropriate staff from the Office of Nuclear Reactor Regulation (NRR) and the Office of Research (RES) to address these concerns.

Originating Document: The originating document was a memorandum (ML033650075) to Dr. William Travers (EDO) from Chairman Nils Diaz, Chairman, dated December 16, 2003, regarding the 'State of U.S. Power Grid from a Nuclear Power Plant Perspective."

Regulatory Assessment: The loss of all alternating current (AC) power at nuclear power plants involves the loss of offsite power (LOOP) combined with the loss of the onsite emergency power supplies (typically emergency diesel generators [EDGs]). This is also referred to as a station blackout (SBO). Risk analyses performed for nuclear power plants indicate that the loss of all AC power can be a large contributor to the core damage frequency, contributing up to 74 percent of the overall risk at some plants. Although nuclear 6

power plants are designed to cope with a LOOP event through the use of onsite power supplies, LOOP events are considered to be precursors to an SBO. An increase in the frequency or duration of LOOP events increases the risk of core damage.

The staff has developed three technical papers on the safety significance of this issue: one on deterministic evaluation, another on risk, and the third incorporating deterministic and risk results. The staff has not identified any safety issues warranting immediate regulatory action. However, since the underlying assumptions in support of the licensing basis have changed, these assumptions will need to be investigated in order to establish a new baseline. The 2004 summer peak season allowed the staff to gain information regarding the licensees capabilities to cope with a loss-of-offsite power event similar to the August 14, 2003, power outage.

Current Status: The NRC staff established a Memorandum of Agreement (MOA) between the NRC and NERC and a MOA between the NRC and FERC. NERC and FERC signed the MOAs on August 27, and September 1, 2004, respectively (ADAM Accession Nos. ML042520329 and ML042580167). In the MOAs, NERC, FERC, and NRC have agreed to consult with each other with regard to the availability of technical information that would be useful in the areas of mutual interest, and to promote and encourage a free flow of such information pertaining to electrical grid reliability, security, and integrity. The staff met with FERC on October 26, 2004, as part of the MOA (ADAMS Accession No. ML043090122). The staff and FERC has also communicated via e-mail and phone to exchange grid-related information impacting nuclear power plants. The staff met with NERC on November 16 and 17, 2004 (ADAMS Accession No. ML043270359), to work on the four Appendices to the MOA: Appendix I - Coordination plan for communications and information sharing during emergencies, Appendix II - Coordination plan for event analysis and follow-up review activities, Appendix III - Coordination plan for the exchange of operational experience data and information, Appendix IV - Coordination plan for participation by NRC staff in NERC committee and subgroup activities. The staff and NERC has also communicated via e-mail and phone to work on the details of the Appendices.

The staff met with the Nuclear Energy Institute and industry representatives on November 3, 2004, to exchange information regarding grid reliability activities (ADAMS Accession No. ML043200234).

The staff presented its grid reliability activities to the Advisory Committee on Reactor Safeguards (ACRS) at the 517 th meeting on November 4, 2004. A transcript can be found on pages 286 through 368 at the following link: http://www.nrc.gov/reading-rm/doc-collections/acrs/tr/fullcommittee/2004/ac 10404.pdf As stated previously, the staff identified 48 issues. The 48 issues are listed in ADAMS Accession No. ML042090490. The staff closed Issue 18 in a memorandum dated September 23, 2004 (ADAMS Accession No. ML042660475). The staff closed Issues 28, 30, 35, 38, 45, and 48 in a memorandum dated September 29, 2004 (ADAMS Accession No. ML042740078). The staff closed Issues 12 and 21 in a memorandum dated November 10, 2004 (ADAMS Accession No. ML043200314).

The staff closed Issues 9, 11, 19, and 20 in a memorandum dated November 10, 2004 (ADAMS Accession No. ML043200359).

In a memorandum dated September 25, 2004 (ADAMS Accession No. ML042740050), the Electrical &

Instrumentation and Controls Branch (EEIB) staff requested assistance from the Probabilistic Safety Assessment Branch (SPSB) staff with two grid-related issues: Issue 36 - Assess the risk impacts of combined loss of offsite power (LOOP) events at multiple units and sites, and Issue 37 - Determine the collective risk for the eight plants affected by the blackout on August 14, 2003. In a memorandum dated October 18, 2004 (ADAMS Accession No. ML042920383), the SPSB staff responded that SPSB believes that the Office of Nuclear Regulatory Research (RES) is the proper office to address Issues 36 and 37. In 7

a November 10, 2004, meeting (ADAMS Accession ML043230237), we discussed the technical and policy issues. We discussed a potential User Need from NRR to RES. The EEIB staff stated that Issues 36 and 37 need to be addressed either pursued or not pursued depending the technical justification. The RES staff stated that it needs to take Issues 36 and 37 back to its Senior Management to discuss. The RES staff said it would like to meet again the week of December 3, 2004. The EEIB staff scheduled a follow-up meeting on December 1, 2004 (ADAMS Accession No ML043500023). The RES staff presented the result of an internal RES meeting addressing the requested effort. The RES staff would like a better definition of the scope: (1) core damage frequency (CDF), large early release frequency (LERF), health effects or all three; and (2) three unit sites, dual unit sites or all sites. The EEIB staff suggested a limited scope based on three unit sites listed in the September 25, 2004, memorandum. The SPSB staff questioned the relationship of Issues 36 and 37 to improving grid reliability. The EEIB staff stated these issues were effects not causes of grid problems. The SPSB staff was tasked with scheduling a Risk-Informed Licensing Panel (RILP) management meeting to determine if a User Need is justified to be sent from NRR to RES. A RILP management meeting was held on December 17, 2004, where the RILP members unanimously voted not to pursue Issues 36 and 37.

On December 7, 2004, the NRR and RES staff met with the Exelon Transmission Operations & Planning staff and the Exelon Nuclear staff regarding grid reliability at the Exelon facility located in Lombard, Illinois.

The purpose of the meeting was to discuss with Exelon how the grid control areas are managed and how the nuclear power plants are accounted for in transmission operations. Further details are available in the meeting summary dated December 23, 2004 (ADAMS Accession No. ML043640066).

On December 9, 2004, NRR briefed the Commission regarding electric grid reliability as part of the briefing on reactor safety and licensing activities. NRR senior management presented slides 14 - 16 regarding electric grid reliability. The complete slides can be found at http://www.nrc.gov/reading-rm/doc-collections/commission/slides/2004/20041209/reactor-safetyjiles/fram e.html. The transcript pages pertaining to grid reliability are 12 - 14, 25 -26, and 48 - 49. The complete transcript can be found at http://www.nrc.gov/reading-rm/doc-collections/commission/tr/2004/20041209.pdf. The Staff Requirements Memorandum (SRM) M041209 dated December 23, 2004, directs the staff to issue a generic communication for public comment no later than April 30, 2005, to raise awareness of grid reliability issues. The staff should provide the Commission a status of its activities related to this generic communication and for ensuring the continued safe operation of plants during the 2005 summer season at the next Commission meeting on grid reliability in March or April 2005 (reference SRM M040510 dated May 18, 2004).

The staff obtained approval by the Leadership Team and the Executive Team on December 16, 2004, to proceed with a generic letter concerning grid reliability.

On December 17, 2004, the staff issued in the Federal Register (69 FR 75570) a notice of availability and draft report for comment for the RES draft report titled, "Evaluation of Loss of Offsite Power Events at Nuclear Power Plants: 1986 - 2003." The comment period expires on January 31, 2005. This draft report is an update of two previous reports analyzing loss-of-offsite power (LOOP) events at U.S. commercial nuclear power plants. LOOP data over the period 1986 - 2003 were collected and analyzed. Frequency and duration estimates for critical and shutdown operations were generated for five categories of LOOPs:

plant centered, switchyard centered, grid related, severe weather related, and extreme weather related.

Overall, LOOP frequencies during critical operation have decreased significantly in recent years, while 8

NRR Technical Contacts: James Lazevnick, DE/EEIB, Offsite Power System Availability Topical Area, 415-2782 Amritpal Gill, DE/EEIB, Station Blackout Review Topical Area, 415-3316 George Morris, DE/EEIB, Risk Insights Topical Area, 415-4074 Thomas Koshy, DE/EEIB, Interactions with Stakeholders Topical Area, 415-1176 Martin Stutzke, DSSAISPSB, Risk, 415-4105 NRR Lead PM: John G. Lamb DE/EEIB, 415-1446 RES

Contact:

Dale Rasmuson, RES/DRAA, 415-7571 Bill Raughley, RES/DSARE, 415-7577 9

DAVIS-BESSE LESSONS LEARNED TASK FORCE RECOMMENDATIONS REGARDING ASSESSMENT OF BARRIER INTEGRITY REQUIREMENTS Last Update: 12131/04 Lead Division: RES/DET Supporting Divisions: DRAA, DSARE Supporting Offices: NRR, Regions TAC No. Description KC0042 Develop and implement action plans based on recommendations of the Davis-Besse reactor vessel head degradation Lessons-Learned Task Force (LLTF)

MB7287 NRR support for development of action plan MC0036 NRR Support to RES for action plan activities Milestone Part l: Leakage

1. a. Review PWR TS to identify plants 7/03 (C) NRR/DIPM that have non-standard RCPB ML031980277 leakage requirements

b. Take appropriate action to make TS 9/04 (C) consistent among all plants. ML042110336

[LLTF 3.3.4(9):High]

2. Inspect plant alarm response procedure requirements for leakage monitoring systems to assess whether they provide adequate guidance for the identification of RCPB leakage. [LLTF 3.2.1 (3)]

a. Revise inspection procedures. 05/04 (C) NRR/DIPM RES/DET NRR/DE NRR/DSSA

b. Assess adequacy of licensee 05105 (T) NRR/DIPM Regions procedure requirements based on results of inspections.

4. Evaluate RCS leakage requirements and leakage detection systems.

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Milestone Date Lead Support (T=Target)

(C=Complete)

a. Perform research study to reevaluate basis for RCS leakage requirements and assess the capabilities of currently used and state-of-the-art leakage detection systems.

(1) Provide initial draft report for 07/04 (C) RES NRR internal staff comment (2) Provide revised report for internal 10/04 (C) RES NRR staff comment NRR (3) Issue final report as NUREG/CR 12/04 (C) RES

b. Form working group to review report and 08/04 (C) NRR/RES make recommendations.

c. Working group to complete a white paper 02/05 (T) NRR/RES to address:

(1) Determine whether PWR plants should install on-line enhanced leakage detection systems on critical plant components, which would be capable of detecting leakage rates of significantly less than 1 gpm.

[LLTF 3.1.5(1):High]

(2) Recommend improvements in the requirements pertaining to RCS unidentified leakage and RCPB leakage to ensure that they are sufficient to: (1) provide the ability to discriminate between RCS unidentified leakage apd RCPB leakage; and (2) provide reasonable assurance that plants are not operated at power with RCPB leakage. [3.2.1(1):High]

(3) Evaluate appropriate regulatory tools to implement recommendations, if necessary.

I .1.

11

Milestone

d. Prepare a memorandum from division , ., .,, I directors to office management to disposition conclusions in staff white paper.

e. Implement approved changes in RCS and TBD RCPB leakage requirements using appropriate regulatory tools.

[3.2.1 (1):High]

Part I. Performance Indicators (PI)

1. Continue ongoing efforts to review and 5/05 (T) NRR/DIPM RES/DRAA improve the usefulness of the barrier integrity RES/DET PIs. Evaluate the feasibility of establishing a NRR/DE PI which tracks the number, duration, and rate NRR/DSSA of primary system leaks that have been Regions identified but not corrected. [LLTF 3.3.3.(3):High]

Part Ill. Risk Associated with Passive Component Degradation

1. Form working group to address 08/04 (C) RES NRR recommendation LLTF 3.3.7(3).

2. Working group to complete a white paper to 02/05 (T) RESINRR address:

- Evaluate the adequacy of analysis methods involving the assessment of risk associated with passive component degradation, including the integration of the results of such analyses into the regulatory decision-making process.

[LLTF 3.3.7(3)]

3. Prepare a memorandum from division 03/05 (T) RES/NRR directors to office management to disposition conclusions in staff white paper.

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==

Description:==

The Reactor Pressure Vessel Head degradation event at the Davis Besse Nuclear Power Station has many safety implications. One concern is the integrity of the reactor coolant pressure boundary. This action plan was developed to improve some of the requirements intended to ensure an effective barrier to the release of radioactivity. This plan describes the required actions, establishes milestone schedules, identifies responsible parties, and estimates resource requirements.

Historical

Background:

In March, 2002, while conducting inspections in response to Bulletin 2001 -01, the Davis-Besse Nuclear Power Station identified three control rod drive mechanism (CRDM) nozzles with indications of axial cracking, which were through-wall, and resulted in reactor coolant pressure boundary leakage. During the nozzle repair activities, the licensee removed boric acid deposits from the RVH, and conducted a visual examination of the area, which identified a 7 inch by 4-to-5 inch cavity on the downhill side of nozzle 3, down to the stainless steel cladding. The extent of the damage indicated that it occurred over an extended period and that the licensee's programs to inspect the reactor pressure vessel (RPV) head and to identify and correct boric acid leakage were ineffective.

One of the NRC follow-up actions to the Davis-Besse event was formation of a Lessons Learned Task Force (LLTF). The LLTF conducted an independent evaluation of the NRC's regulatory processes related to assuring reactor vessel head integrity in order to identify and recommend areas of improvement applicable to the NRC and the industry. A report summarizing their findings and recommendations was published on September 30, 2002. The report contains several consolidated lists of recommendations.

The LLTF report was reviewed by a Review Team (RT), consisting of several senior management personnel appointed by the EDO. The RT issued a report on November 26, 2002, endorsing all but two of the LLTF recommendations, and placing them into four overarching groups. On January 3, 2003, the EDO issued a memo to the Director, NRR, and the Director, RES, tasking them with developing a plan for accomplishing these recommendations. This action plan addresses the Group 4 recommendations of the Davis-Besse Lessons Learned Task Force Review Team regarding the Assessment of Barrier Integrity Requirements. The 6 high priority recommendations in the "Assessment of Barrier Integrity Requirements" grouping are included in this Action Plan. The LLTF recommendations are listed in the attached Table 1, and have been identified under the appropriate milestone(s).

Proposed Actions: The specific LLTF recommendations within this category are focused on reviewing and improving leakage detection requirements. However, simply improving leakage detection and lowering allowable leakage may not be sufficient to provide increased assurance of reactor coolant pressure boundary (RCPB) integrity. Leakage monitoring assumes that the pressure boundary will fail only under a leak-before-break (LBB) scenario. Small leak rates associated with tight stress corrosion cracks or cracks which may be partially plugged are not necessarily associated with small flaws in the RCPB. Therefore, the scope of this action plan also includes methods which may be capable of detecting crack initiation and monitoring crack growth'before a through-wall crack develops and leakage occurs. Other degradation modes, such as boric acid corrosion and erosion-corrosion, which can lead to failure without leakage as a precursor will also be considered.

To support the decision for revising requirements, a comprehensive review and evaluation of plant experiences and current leakage detection systems will be performed. A similar study was performed by Argonne National Laboratory in the late 1980's. This task would essentially be to update that work. The technical bases for the current requirements on leak rates will also be reviewed. If changes should be made to leak rate limits, the impacts of these changes to other plant systems and analyses need to be identified. An evaluation of state-of-the-art systems capable of detecting leaks and cracks will also be completed. This evaluation will include, but is not limited to, acoustic emission technology. An evaluation will also be done to determine if leak rates can be correlated to unacceptable levels of degradation. It should be noted that this evaluation will be more difficult for tight stress-corrosion cracks which typically 13

have low leak rates. Results of these reviews and analyses will then be used to develop an updated basis for leak rate requirements. Once this basis is complete, recommendations will then be made for improving leak rate limits, plant alarm response procedures, TS, and inspection guidance. Then a determination will be made to select which recommendations should be imposed as new requirements.

The appropriate regulatory tools and procedures will be used to develop and implement these new requirements. A regulatory analysis will probably be needed to help establish the appropriate leakage criteria. It may not be possible or practical to implement leakage requirements small enough to preclude failure. Therefore, a regulatory impact analysis will be necessary to establish appropriate risk-informed leakage limits.

In addition to the broad study described above, some other specific activities will be implemented. First, PWR TS will be reviewed to identify plants that have non-standard RCPB leakage requirements (based on current standard TS), and appropriate action will be taken to make TS consistent. Second, inspection guidance for evaluating plant alarm response procedures will be developed and the adequacy of licensee procedure requirements will be evaluated. Finally, inspection guidance will be developed to trigger increasing levels of NRC interaction with licensees in response to increasing levels of unidentified RCS leakage.

The second group of milestones relate to LLTF recommendation 3.3.3(3) regarding the review and improvement of barrier integrity performance indicators (PI). The NRC/Industry ROP Working Group will review the feasibility of establishing a Pi that tracks the number, duration and rate of primary system leaks that have been identified but not corrected, as well as other possible PIs that could monitor RCPB leakage.

Completion of this action plan may require participation in public meetings and establishing communications with stakeholders. These items will be scheduled as needed.

A working group consisting of RES and NRR staff will evaluate the adequacy of risk analysis methods for passive component degradation, including how such analysis results could be incorporated into the regulatory decision making process.

Originating Documents:

Memorandum from Travers, W.D. to Collins, S. and Thadani, A. C., dated January 3, 2003, "Actions Resulting From The Davis-Besse Lessons Learned Task Force Report Recommendations."

[ML023640431]

Memorandum from Paperiello, C.J. to Travers, W.D., dated November 26, 2002, "Senior Management Review of the Lessons-Learned Report of the Davis-Besse Nuclear Power Station Reactor Pressure Vessel Head." [ML023260433]

Memorandum from Howell, A.T. to Kane, W.F., dated September 30, 2002, "Degradation of the Davis-Besse Nuclear Power Station Reactor Pressure Vessel Head Lessons-Learned Report." [ML022740211]

Regulatory Assessment: The reactor coolant pressure boundary forms one of the 3 defense-in-depth barriers to the release of radioactive products. General Design Criteria 14, 30, and 32 of Appendix A to 10 CFR Part 50 specify requirements for the reactor coolant pressure boundary.

• GDC 14 states in part that "[tihe reactor coolant pressure boundary shall be designed, fabricated, erected, and tested so as to have an extremely low probability of abnormal leakage."

14

• GDC 30 states in part that "[m]eans shall be provided for detecting and, to the extent practical, identifying the location of the source of reactor coolant leakage."

• GDC 32 states in part that "[c]omponents which are part of the reactor coolant pressure boundary shall be designed to permit periodic inspection and testing of important areas and features to assess their structural and leaktight integrity."

In addition, the NRC has developed Regulatory Guide 1.45 "Reactor Coolant Pressure Boundary Leakage Detection Systems."

From a practical standpoint, it was recognized that the RCPB cannot be made completely leaktight since some leakage is to be expected from equipment such as pump and valve seals. Therefore, it becomes important to identify the source of any leaks. Identified leaks, such as from valves or pump seals, should be measured, collected, and isolated so as not to interfere with detection of leakage from an unknown source which could indicate a breach of the RCPB. Specific limitations on leakage are stated in the Technical Specifications (TS) for each plant. In general, the TS place a limit on unidentified leakage (usually to 1 gpm) and state that continued operation with RCPB leakage is not allowed. In addition Title 10, Section 50.55a of the Code of Federal Regulations requires plants to meet the requirements of the ASME Boiler and Pressure Vessel Code. Section Xl (Inservice Inspection of Nuclear Power Plant Components) of this code provides acceptance criteria for flaws found during inspection and evaluation procedures for determining the acceptability of flaws exceeding these standards.

Since the vessel head penetration (VHP) nozzles are considered part of the RCPB and significant degradation of the RPV head occurred at Davis-Besse, the issues raised by this event extend beyond problems of stress corrosion cracking in CRDM nozzles to issues of RCPB integrity in general. Primary water stress corrosion cracking of the VHP nozzles and their associated welds has been experienced by both U.S. and foreign plants. In addition, the degradation mechanism that occurred at Davis-Besse was also known. Therefore, one of the conclusions from the LLTF report was that this incident was preventable, but occurred because of a failure to follow-up and integrate relevant operating experience and other available information.

The TS for Davis Besse set a 1 gpm limit for unidentified leakage. In general, unidentified leakage was kept below 0.2 gpm. Despite this conservatism, the leakage eventually caused the degradation found in the vessel head. Therefore, the requirements associated with RCS leakage need to be reviewed and improved as warranted.

Current Status: To address the first milestone in Part 1,NRR completed a review of PWR plant TS in July 2003 and identified plants with nonstandard RCS leakage requirements. The comparison of the PWRs to the STS identified two distinct levels of non-standard reactor coolant pressure boundary TS requirements:

1) units with no TS leakage limit requirement and, 2) units with a TS leakage limit but the TS Action requirements were non-standard.

Only one PWR plant did not have TS for reactor coolant pressure boundary leakage. This licensee submitted a license amendment request to make its TS consistent with the improved STS, and the staff issued the amendment in May 2004. For the other PWR units, the action requirements and completion 15

times when the TS limit is not met are not identical to the STS. However, these plants have a reactor coolant pressure boundary TS leakage limit that is equivalent to the STS, in that the plants will take appropriate conservative actions in the time frame specified in the STS. In addition, the TS for these plants are consistent with the requirements of 10 CFR 50.36(C)(2) in that the reactor must be shut down and plant cool down must be initiated. Therefore, the staff concluded that the TS are consistent among all plants and no additional actions are required.

The second milestone in Part I calls for an inspection of plant alarm response procedure requirements for leakage monitoring systems to assess whether they provide adequate guidance for identifying RCPB leakage. To address this recommendation, inspection guidance has been revised to verify that licensees have programs and processes in place to (1) monitor plant-specific instrumentation that could indicate potential RCS leakage, (2) meet existing requirements related to degraded or inoperable leakage detection instruments, (3) use an inventory balance check when there is unidentified leakage (4) takes appropriate corrective action for adverse trends in unidentified leak rates, and (5) pays particular attention to changes in unidentified leakage. The revised procedures include Inspection Manual Chapter 2515 Appendix D (Plant Status Review), Inspection Procedure 71111.22, and Inspection Procedure 71111.08.

These revisions were issued in May 2004. The assessment of the adequacy of licensee procedure requirements will be completed as part of the annual ROP self assessment process.

The third milestone is also addressed in the revision to IMC 2515, Appendix D. Inspectors are to monitor leakage for adverse trends and notify plant management and regional management if any are noted.

Development of additional technical guidance, such as a tool to determine statistically if a trend exists, is under consideration.

The fourth milestone is being addressed by the Barrier Integrity Research Program that is being performed at the Argonne National Laboratory. The objective of this program is to reevaluate the technical basis for RCS leakage requirements. There are 3 main tasks associated with this effort. The first task is an assessment of the leakage associated with the degradation of various RCPB components.

This includes a review of leak rate experiments and models to identify correlations between crack size and leak rate. A set of leak rate calculations are also being performed using an updated version of the Seepage Quantification of Upsets in Reactor Tubes (SQUIRT) code developed by the NRC. The second task is a review of leakage operating experience by developing a database of leakage events. The information in this database includes (1) leak location, (2) leak rate, (3) cause of leakage, (4) operation of reactor when leak was detected, and (5) action taken. The third task is an evaluation of the capabilities of various leakage detection systems. To date the systems that have been evaluated included acoustic emission, humidity detection, and localized airborne radioactivity monitoring. In addition, this task is evaluating the capabilities of acoustic emission systems to monitor and detect cracking in RCS components before leakage occurs. On March 24, 2004 a program review meeting was held at headquarters in which Argonne and its subcontractors presented interim results of this program to the staff.

At the end of May 2004, ANL provided a draft NUREG report on barrier integrity research. This draft report contains an updated review of RCS leak rate experiments and leak rate models and identifies correlations between crack size, crack opening displacement (COD), and leak rate. Although the focus of this work is on components susceptible to stress corrosion cracking (SCC), other types of materials and cracking mechanisms are considered.

A database was developed which identifies the number, source, rate, and resulting actions from RCS leaks discovered in U.S. LWRs. It describes for each incident what equipment detected the leakage, how it was determined that the leakage was through the pressure boundary, the cause of leakage, and 16

comparisons with applicable leakage requirements. If the leakage was from a crack in the pressure boundary, the crack size, crack type, and measured leak rates are also described. For each incident the database notes what, if any, indications in identified or unidentified leakage were present (i.e., change in some measurement when the pressure boundary was breached).

The capabilities of each type of leakage detection system were evaluated to determine their sensitivity, reliability, response time, and accuracy. The scope of technology considered includes the state-of-the-art in this area, but was limited to technology that can be applied to the monitoring of RCPB conditions in U.S.

LWRs. The evaluations also included crack monitoring systems capable of detecting crack initiation and growth. In addition, technology that can monitor or detect other (non-cracking) degradation modes such as boric acid corrosion or erosion/corrosion was studied. The sensitivity, reliability, response time, and accuracy of these systems, as well as the feasibility of using this technology in nuclear power plant applications have been considered. The systems, procedures, and equipment used in nuclear power plants of other countries to detect leakage were also evaluated.

The RES and NRR staff reviewed this draft report and provided comments for inclusion in the final report.

The revised draft report was available for staff use in October 2004 and the final report was issued as a NUREG/CR in December 2004.

A working group has been formed to use the information contained in the ANL report, as well as other pertinent plant information, to (a) determine if PWR plants should install on-line enhanced leakage detection systems [LTTF No: 3.1.5(1)], and (b) recommend improvements in the requirements for RCS unidentified leakage and RCPB leakage [LLTF No: 3.2.1(1)1.

The Part II milestones regarding Performance Indicators have been revised to indicate more clearly that the response to LLTF 3.3.3(3) is continuation of the ongoing process of working with the industry to improve the Barrier Integrity PIs and to evaluate the feasibility of a Pi that tracks the number, duration and rate of primary leaks that have been identified but not corrected.

Part IlIl milestones were added to track completion of LLTF 3.3.7(3). A working group consisting of RES and NRR staff has been formed and is currently studying the risk assessment methods related to passive component degradation, evaluating their adequacy, and has been periodically meeting and discussing technical challenges and paths to writing a white paper on this issue.

Contacts:

RES Lead

Contact:

Andrea Lee, DET, 415-6696 RES Lead PM: Maketuswara Srinivasan, DET, 415-6356 RES Technical

Contact:

Donald Dube, OERAB, 415-5472 NRR/DIPM Lead

Contact:

Roy Mathew, IlPB, 415-2965 NRR/DLPM Lead

Contact:

Brendan Moroney, DLPM, 415-3974 NRR/DE Lead

Contact:

William Bateman, DE, 415-2795 17

References:

NRC Bulletin 2001-01, "Circumferential Cracking of Reactor Pressure Vessel Head Penetration Nozzles,"

August 3, 2001 Memorandum from Ledyard Marsh, Deputy Director Division of Licensing and Project Management, to John Grobe, Chair, Davis-Besse Reactor Oversight Panel, dated December 6, 2002, "Response to Request for Technical Assistance - Risk Assessment of Davis-Besse Reactor Head Degradation (TIA-2002-01)" [ML023330284]

10 CFR Part 50 Appendix A NRC Regulatory Guide 1.45 "Reactor Coolant Pressure Boundary Leakage Detection Systems" NUREG/CR 4813, "Assessment of Leak Detection Systems for LWR's," May 1988, Argonne National Laboratory.

18

Table 1 LLTF Report Recommendations Included in Barrier Integrity Action Plan High Priority RECOMMENDATION l RECOMMENDATION NUMBER The NRC should determine whether PWR plants should install on-line 3.1.5(1) :nhanced leakage detection systems on critical plant components, which

_ould be capable of detecting leakage rates of significantly less than 1 gpm.

The NRC should improve the requirements pertaining to RCS unidentified eakage and RCPB leakage to ensure that they are sufficient to: (1) provide 3.2.1(1) he ability to discriminate between RCS unidentified leakage and RCPB eakage; and (2) provide reasonable assurance that plants are not operated at power with RCPB leakage.

The NRC should develop inspection guidance pertaining to RCS unidentified eakage that includes action levels to trigger increasing levels of NRC 3.2.1 2) nteraction with licensees in order to assess licensee actions in response to 3.(2) ncreasing levels of unidentified RCS leakage. The action level criteria should identify adverse trends in RCS unidentified leakage that could indicate

__CPB degradation.

The NRC should inspect plant alarm response procedure requirements for 3.2.1(3) eakage monitoring systems to assess whether they provide adequate

_uidance for the identification of RCPB leakage.

The NRC should continue ongoing efforts to review and improve the 3 3.3(3) Usefulness of the barrier integrity Pis. These review efforts should evaluate

.3.( he feasibility of establishing a PI which tracks the number, duration, and rate Pf primary system leaks that have been identified but not corrected.

he NRC should review PWR plant TS to identify plants that have 3.3.4(9) on-standard RCPB leakage requirements and should pursue changes to hose TS to make them consistent amona all plants.

Medium Priority 3.3.7(3) Evaluate the adequacy of analysis methods involving the assessment of risk associated with passive component degradation, including the integration of the results of such analyses into the regulatory decision-making process.

19

DAVIS-BESSE LESSONS LEARNED TASK FORCE RECOMMENDATIONS REGARDING INSPECTION, ASSESSMENT, AND PROJECT MANAGEMENT GUIDANCE TAC No. Description Last Update: 12131/04 MB7281 Develop Action Plan Lead Division: DIPM MB7726 Evaluation of Inspection and Supporting Division: DLPM Assessment Guidance Supporting Office: Regions Milestone l Date Lead Support (T=Target)

(C= Co m plete)

Part 1 - Evaluation of Inspection Guidance Related To Problem Identification and Resolution The NRC should revise its inspection guidance to provide assessments of: (1) the safety implications of long-standing, unresolved problems; (2) corrective actions phased in over several years or refueling outages; and (3) deferred modifications.

[LLTF 3.2.5.(2) High]

The NRC should revise the overall PI&R inspection approach such that issues similar to those experienced at DBNPS are reviewed and assessed.

The NRC should enhance the guidance for these inspections to prescribe the format of information that is screened when determining which specific problems will be reviewed. [LLTF3.3.2.(2) Low]

The NRC should provide enhanced Inspection Manual Chapter guidance to pursue issues and problems identified during plant status reviews

[LLTF3.3.2.(3) Low]

The NRC should revise its inspection guidance to provide for the longer-term follow-up of issues that have not progressed to a finding.

[LLTF3.3.2.(4) Low]

1. Make changes to IP 71152 to require 01/02 (C) DIPM annual follow-up of three to six issues.

2. PI&R focus group assess lessons learned 03/03 (C) DIPM Regions recommendations.

3. Develop draft procedure changes based on 04/03 (C) DIPM Regions PI&R group recommendations and provide ML031390010 to regions for review.

20

Milestone Date Lead Support (T=Target)

(C=Complete)

4. Provide training on procedure changes. 09/03 (C) DIPM

5. Issue procedure changes. 09/03 (C) DIPM Part 2 - Evaluation of IMC 0350 Guidance The NRC should develop guidance to address the impacts of IMC 0350 implementation on the regional organizational alignment and resource allocation.

[LLTF3.3.5.(4) High]

1. Assess past and present IMC 0350 data 06/03 (C) DIPM Regions and associated inspection approaches. M1031890873

2. Develop enhanced structure to the 08/03 (C) DIPM Regions inspection approach used for IMC 0350 ML032250336 plants.

3. Develop draft revisions to IMC and issue for 10/03 (C) DIPM regional comment.

4. Issue procedure revisions. 12/03 (C) DIPM

5. Include estimated resources for IMC 0350 12103 (C) DIPM plants into budget cycles. ML033010385 Part 3 - Evaluation of Project Management Guidance The NRC should establish guidance to ensure that decisions to allow deviations from agency guidelines and recommendations issued in generic communications are adequately documented. [LLTF 3.3.7.(2) High]

1. The DLPM Handbook will be updated with a 02/03 (C) DLPM new section that addresses documenting staff decisions.

2. A training package emphasizing compliance 04/03 (C) DLPM with the requirements of MD 3.53 will be ML030300067 developed and distributed to all Offices and regions.

3. Issue Office Instruction on Generic 06/03 (C) DRIP DLPM Communications ML023170311 21

Milestone Date Lead Support (T=Target)

(C=Complete)

4. Conduct effectiveness review:

a. Follow up with Offices and Regions 07/04 (C) DLPM to determine effectiveness of ML041200528 training.

b. Review sample of generic 06/04 (C) DLPM communication closeouts for ML041810128 appropriate documentation.

c. Complete additional training and 03/05 (T) DLPM procedure revisions as indicated by effectiveness review.

==

Description:==

The Davis Besse Lessons Learned Task Force (LLTF) identified several issues concerning the NRC's oversight, inspection, and project management guidance. The LLTF recommended that changes be made to the NRC's inspection program to ensure that sufficient inspections are conducted of long-standing unresolved problems, that guidance be developed to assess the impacts of Inspection Manual Chapter 0350 on regional resource allocations, and that guidance be developed to ensure that decisions to allow deviations from agency guidelines in generic communications are adequately documented.

Historical

Background:

The Davis Besse LLTF conducted an independent evaluation of the NRC's regulatory processes related to assuring reactor vessel head integrity in order to identify and recommend areas of improvement applicable to the NRC and the industry. A report summarizing their findings and recommendations was published on September 30, 2002. The report contains several consolidated lists of recommendations. The LLTF report was reviewed by a Review Team (RT), consisting of several senior management personnel appointed by the EDO. The RT issued a report on November 26, 2002, endorsing all but two of the LLTF recommendations, and placing them into four overarching groups. On January 3, 2003, the EDO issued a memo to the Director, NRR, and the Director, RES, tasking them with a plan for accomplishing the recommendations. This action plan addresses the Group 3 recommendations of the Davis-Besse Lessons Learned Task Force regarding inspection, assessment, and project management guidance. As directed by the EDO's memo, this action plan includes the 3 high priority recommendations in the "Evaluation of Inspection, Assessment, and Project Management Guidance" grouping. In addition, three low priority recommendations are included since they are closely related to the high priority recommendations and will be accomplished in conjunction with the work necessary to resolve the high priority items. The LLTF recommendations are also listed in the attached Table 1.

Proposed Actions: Parts 1, 2, and 3 of this action plan are unrelated and will be worked as three independent efforts. The recommendations associated with the inspection program will be reviewed by the Problem Identification and Resolution (PI&R) focus group which is made up of headquarters and regional representatives. The focus group will assess whether changes to the current PI&R inspection approach are warranted. Procedure changes will then be made as appropriate, and inspector training will be conducted.

22

The recommendation associated with IMC 0350 will be assessed by evaluating the previous inspection approaches used and associated resource expenditures for plants that entered the IMC 0350 process.

The staff will then attempt to better define a more enhanced inspection framework for a plant that enters IMC 0350. Once this additional inspection guidance is completed, a better estimate of resources will be made, and resources for IMC 0350 will be included in budget projections.

Project management guidance regarding documentation when accepting deviations from generic communications recommendations will be incorporated into the DLPM handbook and into training materials to be distributed to all Offices and Regions. An Office Instruction will be issued to provide guidance on preparation, issuance and closeout of generic communications.

Originating Documents:

Memorandum from Travers, W.D. to Collins, S. and Thadani, A. C., dated January 3, 2003, "Actions Resulting From The Davis-Besse Lessons Learned Task Force Report Recommendations."

(ML023640431)

Memorandum from Paperiello, C.J. to Travers, W.D., dated November 26, 2002, "Senior Management Review of the Lessons-Learned Report of the Davis-Besse Nuclear Power Station Reactor Pressure Vessel Head." (ML023260433)

Memorandum from Howell, A.T. to Kane, W.F., dated September 30, 2002, "Degradation of the Davis-Besse Nuclear Power Station Reactor Pressure Vessel Head Lessons-Learned Report."

(ML022740211)

Regulatorv Assessment: It is not anticipated that this action plan will result in any additional regulatory requirements on licensees. The plan focuses on what enhancements should be made to existing inspection and project management guidance to ensure better scope, efficiency, and documentation of such activities.

Current Status: Part 1 milestones are complete. The procedure changes have been issued and a training module was placed on the web-based "Read and Sign" training for inspectors. Inspection Procedure (IP) 71152, Identification and Resolution of Problems," was revised to require the resident inspector to perform a screening review of each item entered into the corrective action program. The intent of this review is to be alert to conditions such as repetitive equipment failures or human performance issues that might warrant additional follow-up through other baseline inspection procedures. IP 71152 was also revised to require a semi-annual review to identify trends that might indicate the existence of a more significant safety issue. Included within the scope of this review are repetitive or closely related issues that may have been documented by the licensee outside the normal corrective action program, such as in trend reports or performance indicators, major equipment problem lists, repetitive and/or rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self-assessment reports, maintenance rule assessments, or corrective action backlog lists. Finally, IP 71152 was revised to include enhanced requirements regarding routine PI&R reviews conducted by the resident inspectors, biennial reviews of longstanding issues, and biennial reviews of licensees' operating experience issues.

23

To address the issue of deferred modifications, the staff revised IP 71111.15, "Operability Evaluations."

The objective of this procedure is to review operability evaluations affecting mitigating systems and barrier integrity to ensure that operability is properly justified and the component or system remains available, such that no unrecognized increase in risk has occurred. The procedure was revised to include deferred modifications as one of the areas an inspector can assess to ensure that structures, systems, and components are capable of performing their design function.

Part 2 milestone activities have been completed. The Inspection Program Branch completed an evaluation of the IMC 0350, "Oversight of Operating Reactor Facilities in a Shutdown Condition with Performance Problems," process in June 2003, (ML031890873). It identified the need for specifically budgeting resources for [MC 0350 inspections and providing prescriptive inspection guidelines for the process. The budget estimate was increased for FY2005 and beyond (ML033010385) to account for one IMC 0350 plant per year. IMC 0350 was revised in December 2003, to provide additional inspection guidelines.

The Part 3 milestones associated with issuing guidance were completed as scheduled. The milestones to follow up on the effectiveness of training and to perform a review of a sample of recent generic communications for proper closeout documentation are complete.

The effectiveness evaluations indicated a need for additional action to improve guidance documents and to conduct additional training. This was added to the action plan.

Contacts:

NRR Lead for this action plan: Stuart Richards, DIPM, 415-1257 Overall Lead for DB LLTF response: Brendan Moroney, DLPM, 415-3974

References:

Inspection Manual 0350, "Oversight of Operating Reactor Facilities in an Extended Shutdown as a Result of Significant Performance Problems."

24

Table 1 LLTF Report Recommendations Included in This Action Plan RECOMMENDATION RECOMMENDATION PRIORITY NUMBER 3.2.5.(2) The NRC should revise its High inspection guidance to provide assessments of: (1) the safety implications of long-standing, unresolved problems; (2) corrective actions phased in over several years or refueling outages; and (3) deferred modifications.

3.3.2.(2) The NRC should revise the overall Low PI&R inspection approach such that issues similar to those experienced at DBNPS are reviewed and assessed. The NRC should enhance the guidance for these inspections to prescribe the format of information that is screened when determining which specific problems will be reviewed.

3.3.2.(3) The NRC should provide enhanced Low Inspection Manual Chapter guidance to pursue issues and problems identified during plant status reviews. [3.3.2.(3)]

3.3.2.(4) The NRC should revise its Low inspection guidance to provide for the longer-term follow-up of issues that have not progressed to a finding.

3.3.5.(4) The NRC should develop guidance High to address the impacts of IMC 0350 implementation on the regional organizational alignment and resource allocation.

25

3.3.7.(2) The NRC should establish guidance High to ensure that decisions to allow deviations from agency guidelines and recommendations issued in generic communications are adequately documented.

26

SIGNIFICANCE DETERMINATION PROCESS (SDP) IMPROVEMENT TAC Nos. MA9164, MB0046, & MB2203 Last Update: 12/31/04 Lead Division: DIPM Supporting Division: DSSA Mission: To improve the effectiveness and efficiency of the Significance Determination Process (SDP), consistent with the vision. The Plan delineates assigned responsibilities and completion dates for the tasks to achieve the stated objectives.

Coordinator: Peter Koltay, IIPB/DIPM/NRR Task - DteLead ] Status

1. Improve Focus on Early Resolution of Specific Technical Questions and Internal Staff Disagreements Objective 1.1 Implement a weekly 04/01/02 (C) IIPB SDP Activities Tracking List management status implemented 2/1/02 to report on SDP issues in address Objectives 1.1-1.2.

process. [SDP 3.9.3(1)]

Objective 1.2 Incorporate features to 12/31/05 (T) IIPB The Active Issues Matrix provide for early communicates a running identification of SDP summary of active SDP issues that are likely to findings focusing senior HQ become untimely due to and regional managers' technical, policy, or attention on timeliness process issues. issues. This previously

[OIG - 6] closed issue is being re-opened pending measurable success in meeting the timeliness requirements.

See note under the section titled "Potential Problems" at the back of this document.

Objective 1.3 Develop and track/trend 06/28/02 (C) IIPB IMC 0307, Reactor SDP timeliness metrics Oversight Process Self-within ROP Self- Assessment Program, Assessment Process, incorporates the relevant including the cycle-time timeliness metrics.

calculation for major process steps.

27

[ Task C e ead. j , Stats I Objective 1.4 Implement a 06/28/02 (C) IIPB IMC 0307 changed to reflect requirement to conduct requirement to conduct self-a self-assessment for assessments during annual SDP results that are not review of baseline timely. procedures.

Objective 1.5 Rectify the difference 10/11/03 (C) IIPB Timeliness goals in the NRR between the NRR Operating Plan are Operating Plan and referenced in IMC 0609.

IMC 0307 for SDP timeliness. [SDP 3.9.3(3)]

Objective 1.6 Incorporate SDP 12/30/03 (C) IIPB Memorandum from NRR to timeliness metrics Into the regions explaining the Regional Operating timeliness goals are Plans. [SDP 3.9.3(1)] included into the regional operating plans (ML0321602552).

Objective 1.7 Change IMC 0307 UROP 12/30/03 (C) IIPB IMC0307, ROP Self Self-Assessment Assessment, Section Program" to improve 06.01b6, Timeliness of evaluation of inspection Identification, addresses the effectiveness in timely issue.

identification of performance deficiencies. [OIG - 5]

2. Improve SDP Process Objective 2.1 Revise Attachment 1 of Complete IIPB l IMC 0609 Att. 1was revised IMC 0609 to clarify the April 30, 2002, to roles and responsibilities incorporate this of the SERP, to include enhancement to the an escalation process SERP process.

for resolution of issues for which the SERP cannot reach a consensus position, and to include process timeliness goals.() l l l 28

Task l

`6CmplIetion l : l ea-I Status

a. Clearly define the accounting 08/01/02 (C) Guidance is provided in process of the 90 day time IMC 0609 Att. 1 and tracked period including: under Objective 1.1 of the Starting time Plan.

End time

b. Communicate the Agency's 12/01/03 (C) Timeliness goals have been timeliness goals to licensees and will continue to be (e.g., Choice Letters, Regulatory communicated to all Conferences, Reg. Information stakeholders through all Conference, etc.). identified interactions. This

[SDP 3.9.3(2)] change will also be incorporated into next revision of IMC 0609.01 (Choice Letter), in FY 2004.

c. Improve the SERP process: 06/28/02 (C) IMC 0609 Att. 1 was revised Clearly identify SERP April 30, 2002, to identify participants and define their SERP participants and their respective roles and roles and responsibilities.

responsibilities in IMC0609.01.

d. Outline the escalation process 06/28/02 (C) IMC 0609 Att. 1 was revised for issues where the SERP fails April 30, 2002, to outline the to reach consensus in escalation process when IMC0609.01. SERP fails to reach Consensus.

e. Improve the Regulatory 6/28/02 (C) IMC 0609 Att. 1 was revised Conference process and April 30, 2002, to improve associated activities: the effectiveness of the Designation of NRC participants Regulatory Conference and Post conference caucus post-conference caucus.

Post conference re-SERP Post conference SDP and re-SERP.

29

l i; lll.Tas -1Status Objective 2.2 Engage the regions to Complete IIPB Routine bi-weekly confirm their teleconferences are held understanding and Support: with the Regions. NRR implementation of the SPSB emphasizes expectations expectations regarding noted in IMC 0609 and the use of the SDP, August 9, 2002, including guidance on memorandum from the level and type of S. Collins to the Regional licensee engagement Administrators on "Reactor that is appropriate Oversight Expectations for during the conduct of:(2) Inspector Use of the

[SDP 3.2.3(2)] Significant Determination Process". This memo provides specific instructions on the level and type of licensee engagement for each phase of the SDP.

a. SDP Phase 2 risk analyses. 08/01/02 (C)

b. SDP Phase 3 risk analyses. 08/01/02 (C)

c. Communicate expectations for 08/01/03 (C) A revised "Expectations" inspector use of the phase 2 memorandum provides clear notebooks during interim period instructions regarding the in which enhanced pre-solved use of the phase 2 risk tables are being developed. notebooks during the development of the pre-solved SDP tables.

ML031270689 30

I Task Dat L S  ;

Objective 2.3 Issue guidance on the Complete IIPB Based on experience gained use of the site specific from the initial notebook risk-informed inspection Support: benchmarking efforts and notebooks (hence SPSB HOP implementation, referred to throughout additional notebook usage this document as the guidelines were developed notebooks) within the and presented to SRAs for overall context of the discussion and comments.

SDp (2.3) The final version of the guidelines were incorporated into 'Expectations Memorandum" and IMC 0609.

a. Use of the revision 0 notebooks 05/31/02 (C)

(pre-benchmarking).

b. Use of the benchmarked 05/31/02 (C) notebooks, revision 1.

c. Guidance when additional 05/31/02 (C) analysis beyond the capability of the notebooks needs to be conducted.

Objective 2.4 Evaluate revising the Complete IIPB This issue was presented to SDP to require that the the DRP/DRS Division preliminary Directors during the characterization of August 20-21, 2002, potentially risk counterpart meeting and the significant issues be proposed change to 0609 "potentially greater than was issued for review and green," rather than a comment. The proposed specific color.Q2 ) revision to the 0609

[SDP 3.9.3(4)] guidance was also discussed during the January 2003 ROP public meeting.

a. Collect and evaluate regional 01/31/03 (C) input.

31

l-' Task- La 4 Status

b. Make final determination on 04/30/03 (C) The revision to IMC 0609 changing the process to Att. 1 was issued on preliminary greater than green, March 21, 2003, to allow for or stay with the existing process the use of "greater than or preliminary specific color. green" preliminary SDP characterization.

Objective 2.5 Assemble a focus group Complete IIPB The SDP Task Group was of internal stakeholders formed consisting of to identify key SDP- Support: regional and headquarters related issues going SPSB, staff. A charter was forward and provide Regions developed and the SDPTG recommendations for completed a comprehensive their resolution, review of the SDP and consistent with the ROP provided recommendations principles and to enhance the overall objectives.! 3" effectiveness of the process.

The recommendations have been accepted by NRR and incorporated into this Plan, as noted.

a. Identify focus group members. 05/01/02 (C) l

b. Develop charter. 06/28/02 (C) l

c. Present recommendations. 12/20/02 (C)

Objective 2.6 Develop a plan for long Complete The SDP Improvement range improvements to Initiative Task Action Plan is the SDP.( 3 ) [OIG-1] NRR's tool for tracking SDP improvement activities.

32

Taskate -ll Lead tatus

a. Issue the proposed SDP basis 05/30/04 (C) IIPB, SPSB provided the document, including the current SPSB notebook construction rules, performance expectations for to be incorporated into the the notebooks. The notebook basis document, in April 04.

"construction rules" should also The revised Inspection be included or referenced in the Manual Chapter IMC 0308, proposed SDP Basis Document. "Reactor Oversight Process

[SDP 3.2.3(1)] [SDP 3.6.3(4)] Basis Document", was issued June 2004.

b. Re-evaluate the performance 03/31/04 (C) IIPB Evaluation of SDP expectations of the SDP tools effectiveness and after completion of the notebook performance expectations is benchmarking and modify conducted as part of the program guidance, as routine annual assessment appropriate, to reflect any process outlined in revisions to the expectations. IMC 0307. A re-evaluation

[SDP 3.2.3(3)] of the benchmarked notebooks resulted in the ongoing notebook standardization process identified in Objective 3.1 c.

3. Improve SDP Tools Objective 3.1 Revise IMC 0609 App. A SPSB to improve the guidance for conducting a phase 2 Support:

analysis to:(3) IIPB

a. Develop tools and simplify the TBD (Multi- SPSB The pilot was completed process of accounting for year effort) 09/04. Draft report based on external initiators in phase 2 of the pilot is under evaluation.

the SDP. Parallel options under consideration, one to coordinate with RES under the RASP program in developing the external event SPAR models. This requires significant owners group contribution as well; at the same time consider the enhancement of the phase 2 notebooks to include guidance for accounting for external event risk contribution.

33

t J t-Task ta ]

b. Clarify the guidance on the 04/01/02 (C) Guidance incorporated in treatment of concurrent issues. March 18, 2002, revision to IMC 0609 App. A Section lii.

c. Standardize benchmarked 12/31/2005 (T) SPSB Notebooks that were notebooks and develop pre- benchmarked during the solved risk tables from early stages of the initiative standardized (re- benchmarked) will be revised to incorporate notebooks. [SDP 3.1.3(2)] lessons learned from the

[SDP 3.6.3(1)] [OIG-1] benchmarking process.

This may require approximately 10 additional site visits. Notebooks will be standardized by completing the re- benchmarking process and ready to be issued as revision 2 by 06/30/05. Each Revision 2 notebook will include the basic pre-solved tables with the value of each sequence identified. After the issuance of Revision 2 a spreadsheet for each notebook will be prepared each containing a comprehensive target set of plant-specific key components and operator actions. The spreadsheets will be available in early 2006.

d. Evaluate training needs and 10/30/05 (T) IIPB Supplemental training needs issue revised guidance for the will be evaluated prior to use of the pre-solved risk tables. issuance of the pre-solved risk tables.

34

Task ' 'ml tn Lead- Sta us Objective 3.2 Develop a plan to SPSB benchmark and revise all of the notebooks Support:

(Revision 1). Develop IIPB and implement a quality assurance (QA) plan for the development of revision 1to the notebooks.(2 3)

[SDP 3.1.3(2)]

a. Schedule and complete 10/01/03 (C) All benchmarking trips benchmarking plan (site visits) completed. Final Revision 1 notebooks are available to internal stakeholders on the DSSA/SPSB and SRA web l pages. (See Objective 3.1c)

b. Develop and implement QA plan 03/01/02 (C) QA Plan developed and for development of the provided to BNL for notebooks. development of the notebooks.

c. Implement a process to 09/30/03 (C) All benchmarking has been compare the results of the QA'd completed. Outcomes SPAR models and benchmarked continue to be verified.

notebooks. [SDP 3.6.3(3)] _

d. Develop notebook maintenance TBD This will be accomplished on schedules to review and update a case by case basis. No the phase 2 tools to address funding or FTE has been licensee PRA changes and/or allocated for this effort.

plant modifications. [SDP 3.6.3(2)]

Objective 3.3 Develop or improve existing SDP tools as applicable in the following areas: [OIG-3]

35

Task J i l Lea Status

a. Fire protection 05/31/04 (C) SPSB Three training sessions attended by most fire protection inspections and SRAs have been completed.

Recent field experience in implementation is being collected and evaluated.

b. Maintenance rule 03/30/05 (T) SPSB/ Internal stakeholder IIPB comments are being incorporated.

c. Containment 05/30/04 (C) IIPB Issued to industry and NRC regions for review and comments May 03. Public meeting participation in July.

Training has been completed.

d. Steam generator tube integrity 04/30/04 (C) IIPB Public meeting with NEI participation was held on 09/24/03. Some industry comments have been resolved. A new draft SDP will be issued to stakeholder comments at the October ROP meeting. SPSB will be the primary user of this guidance.

e. Shutdown 05/30/04 (C) SPSB/ SDP presented to NEI and IIPB SRAs July 2002 and October 2002. Workshop held January 2003.

Enhanced Appendix G to be issued November 2003.

Training has been completed.

f. Spent Fuel TBD IIPB Under development.

A new completion date for this SDP will be determined during the first quarter of l_ 2005.

36

l.T L'Cmask~-

~.

:... .7.: _ _ _

D'ateleton

_ _ _ lol_

Lead

-L _l _5 tlu Objective 3.4 Improve the physical 12/31/04 (T) NSIR A trial implementation of the protection SDP, if Commission approved base necessary, accounting Support: line and force on force SDPs for any safeguards IIPB is completed. Results under policy changes. evaluation for assessing final implementation in February 2005.

Objective 3.5 Develop a database of 10/01/02 (C) SPSB Database of submitted all completed phase 3 phase 3 analyses was analyses.(3) created and is accessible via the SPSB web page.

Continuing to add information. Link at http:nrr.gov/adt/ds/sa/

spsb/webpages/srapa/

ge/phase3_,serps/rop-case-status.html Objective 3.6 Consider development 6/28/02 (C) SPSB 11/26/02, RES developed of analysis criteria and procedures incorporating standards for conducting Support: high level ASP guidance.

detailed phase 3 RES, The documents were analysis.(3) [SDP Regions provided to the SRAs for 3.5.3(2)] [OIG-4] review to determine applicability to the phase 3 SDP.

a. Identify participating RES and 8/30/03 (C) NRR/SPSB and RES NRR personnel and establish initiated the Risk responsibilities and a completion Assessment Standardization schedule. Project (RASP) to develop standard methodologies and procedures for conducting phase 3 analyses.

37

l; -Task sk-

tIo Copltion Dat 1La V

l' -

S Sitatu

b. Develop criteria and to allow the 04/30/05 (T) RES The RASP will evaluate the staff to recognize situations Support: possibility for developing where "the state of knowledge" SPSB/ advanced risk criteria for correlation, which is described in IIPB recognizing when modeling RG 1.174, might warrant a parameter uncertainties Phase 3 analysis. [SDP warrant a more in-depth 3.7.3(1)] analysis to properly characterize the significance of an inspection finding. The RASP developed an operating plan which includes addressing this area as per the indicated schedule.

c. Develop guidance to allow the TBD SPSB The staff determined that staff to determine whether the guidance incorporated into results of a licensee's risk the ROP documents, analysis of a finding is of IMC 0609.01 and the sufficient quality to use as an notebooks, provide the input to the staff's final assurance that licensee risk significance determination. analyses consider the

[SDP 3.11.2.3(1)] [OIG-4] appropriate assumptions and uncertainties.

Additionally, Regulatory Guide 1.200 published February 2004 provides an approach for determining the technical adequacy of PRA results for risk-informed activities.

The RASP action plan calls for the development of a checklist, based on RG 1200, allowing inspectors and SRAs to verify the quality of the basis for the l _ _ _ __ _licensee's risk analyses.

38

- ; -Task

'w -- t I_'Lea l-_Status Objective 3.7 Evaluate accelerating RES the SPAR Model Development Program (i.e., Revision 3i SPAR models, low power/shutdown models, LERF models, and external events analysis capability).{2 _

a. Develop Rev. 3i SPAR models. 9/30/02 (C) Complete.

b. Complete onsite QA verification 10/31/03 (C) Complete.

(benchmarking) of Rev. 3i SPAR models.

c. Develop Low Power/Shutdown 12/31/05 (T) RES is developing generic model. templates for each class of licensed reactor plants.

Four models have been completed.

d. Develop LERF model 12/31/06 (T) Draft event trees have been developed.

4. Improve Staff Training in The Use of SDP Tools Objective 4.1 Develop and conduct Complete IIPB training on the use of the notebooks. Develop Support:

initial and periodic SPSB/

refresher training on the TTC SDP.( 3 1

a. Develop training materials for 4/15/02 (C) Complete.

IMC 0609A revision.

b. Complete IMC 0609A training at 10/01/02 (C) Complete.

inspector counterpart meetings:

[OIG-3] .

39

a; - eaTask - Status

c. Encourage regions to conduct 6/30/03 (C) Refresher training will be annual SDP refresher training provided by regional and during routine inspector headquarters SRAs on an seminars. [SDP 3.5.3(1)] annual basis.

d. Develop systematic assessment 1/31/04 (C) NRR's Risk Informed of training needs in the area of Environment Initiative and risk, with a particular focus on IMC 1245 Working Groups identifying and advancing the are engaged in evaluations knowledge, skills, and abilities of the necessary skills and (KSAs) for implementing the training needs as they relate SDP. [SDP 3.5.3(3)] to understanding and using risk in regulatory activities.

Based on their evaluations, the groups will make recommendations to enhance the training program for inspectors and risk analysts and propose improvements to staff processes, practices, and infrastructure.

Objective 4.2 Increase staffing and/or 6/30/02 (C) IIPB NRR has staffed additional staff development in the SRA positions within SPSB.

areas of shutdown risk, Support: The newly hired staff is seismic, fire protection, SPSB currently completing and containment risk required training for SRA analysis. [OIG-3] certification.

40

l  ;-.Task Jas Completion frStatus l Ld Le -

_ _ __ __ _ _ _ _ _ _ _ _ _ _ _ _ "M ate -

5. Improve Clarity of Risk-informed ROP Decision Guidance Objective 5.1 The staff will develop 12/31/05 (T) IIPB The staff determined that a guidance on the cost-benefit evaluation is not termination of ongoing the appropriate measure to risk evaluations when it determine when the ongoing is clear that such activity refinement of the risk will result in exceeding evaluation should be timeliness guidelines. terminated. The staff determined that in order to meet the timeliness guidelines, the termination of ongoing refinement of risk evaluations should be based on management assessment of available information including understanding of uncertainties associated with the issue, and the plausibility of forth coming information within the timeliness guidelines. The entire issue of SDP timeliness is under review. The change in date reflects the ongoing effort which will be proposed in a SECY paper.

Objective 5.2 Develop guidance that 03/26/03 (C) IIPB The attributes for reaching defines the attributes of the minimally acceptable a minimally acceptable Support: risk-informed decision are risk-informed decision SPSB described in IMC 0609 for use within the ROP. Att. 1, Exhibit 4.

[OIG-3]

41

Task Ii =o- .- .ead Lead [ ' Status status:C "i Y I Y Objective 5.3 Revise the ROP 12/31/05 (T) IIPB IIPB is in the process of guidance to explicitly identifying findings where indicate that traditional Support: this could be applicable and engineering analysis SPSB developing guidance for considerations (e.g., Regions evaluating issues when reduction of safety there is a significant margin, or significant reduction of safety margin or loss of defense-in- loss of defense-in-depth.

depth) should be used to determine an appropriate color to associate with findings where the uncertainty in the risk evaluation arising from the characterization of the impact of the inspection finding is large enough that the color is indeterminate on the basis of the risk analysis. This guidance should promote consistency and be used only where the uncertainty is significant (i.e., when alternate assumptions yield results which vary over more than two orders of magnitude). [SDP 3.7.3(2)] -

J 42

Task Leadd,

.Leaa US

• i ate -

6. Clarify Expectations for ASP and SDP Process Coordination Objective 6.1 Issue guidance to 06/30/04 (C) IIPB Currently, based on a user delineate the role of the need memo, RES reviews Office of Research in Support: all greater than green issues the SDP, in order to RES and provides independent minimize the potential reviews a quarterly for unexpected or assessment of the specific unreasonable implementation of the differences in the results process. To date, all of the SDP and ASP differences were minor, processes. Explore resulting from variation in efficiencies and quality risk assessment enhancements that methodology, and were would result in better promptly resolved. This coordination and/or independent review integration of these two program will continue programs. indefinitely.

[SDP 3.11.1.3(1)]

a. NRR and RES should TBD IIPB This issue is under Review identify avenues to Support by the IMC 1245 Working enhance the staff's SPSB Group.

knowledge of the ASP /RES program, including adding a module to the P-111 course regarding the ASP program. [SDP 3.11.1.3(2)]

(1) Staff Requirements Memorandum M010720A of August 2, 2001, which resulted from the Commission briefing on the results of initial implementation of the reactor oversight process held on Friday, July 20, 2001.

(2) Staff Requirements Memorandum of February 5, 2002, resulting from COMEXM-01 -0001, D.C.

Cook Potential Red Finding, and the Implementation of the Significance Determination Process Within the Reactor Oversight Program (3) Response to Differing Professional View NRR-02-DPV-02, dated February 18, 2002, concerning the continued performance of significance determination process phase 2 analysis (4) Memorandum dated December 20, 2001, from Ellis Merschoff, Regional Administrator, Region IV, and Frank Congel, Director, Office of Enforcement, to Samuel Collins, Director, Office of Nuclear Reactor Regulation, on the treatment of programmatic issues by the SDP.

43

==

Description:==

In conjunction with IMC 2515, "The Policy For the Light-Water Operating Reactor Inspection Program", IMC 0609, "The Significance Determination Process (SDP)", was developed to assist the staff in using risk insights, where appropriate, to help NRC inspectors and staff determine the safety significance of inspection findings. The appendices to IMC 0609 support safety cornerstones associated with the strategic performance areas as defined in IMC 2515. The SDP determinations for inspection findings and the Performance Indicator (PI) information are combined for use in assessing licensee performance in accordance with guidance provided in IMC 0305, "Operating Reactor Assessment Program."

The SDP is an essential component in the ROP that serves to improve the objectivity of the ROP so that subjective decisions and judgment are not central process features. The SDP is an objective, risk-informed, and scrutable process that ensures that NRC resources are focused on those aspects of plant performance having the greatest impact on safe plant operation and that NRC actions have a clear tie to licensee performance.

Historical

Background:

In SECY-99-007, "Recommendations for Reactor Oversight Process Improvements," dated January 8, 1999, the staff provided its recommendations to the Commission for improving the reactor regulatory oversight processes, including proposed changes to the NRC's inspection, assessment, and enforcement processes. The staff's efforts to develop the proposed changes was guided by three objectives: 1) improve the objectivity of the [reactor] oversight process so that subjective decisions were not central process features; (2) improve the scrutability of these processes so that NRC actions have a clear tie to licensee performance; and (3) risk-inform the process so that NRC and licensee resources are focused on those aspects of performance having the greatest impact on safe plant operations. With respect to the assessment process, the staff sought to develop a process that would allow the integration of various information sources relevant to licensee safety performance. In SECY 007, the staff concluded that adequate assurance of licensee performance would be achieved through the use of risk-informed performance indicators (Pis) and inspection findings. The staff also highlighted the need to develop a method for characterizing the risk of inspection findings and indicated that a "level of risk significance, based on a risk scale, will be determined and documented for the findings."

In SECY-99-007A, Recommendations For Reactor Oversight Process Improvements" (follow-up to SECY-9-007), Attachment 2, dated March 22, 1999, the staff introduced the Significance Determination Process (SDP) as the method for characterizing the risk of inspection findings. The SDP was designed to assess only those inspection findings associated with at-power operations in the Reactor Safety Strategic Performance Area cornerstones of Initiating Event (IE), Mitigating Systems (MS) and Barrier Integrity (BI);

however, concepts for characterizing the risk significance of inspection findings in the emergency preparedness, radiation safety, and safeguards areas were under development. The SDP provided a means to screen out inspection findings that have minimal or no risk significance and trigger a more detailed analysis of potentially risk-significant findings.

To support the start of the initial implementation of the revised Reactor Oversight Process (ROP) in April 2000, the staff issued Inspection Manual Chapter (IMC) 0609, "Significance Determination Process."

Appendix A to IMC 0609 provided guidance for the staff to estimate the unintended increase in risk during at-power plant conditions caused by deficient licensee performance. The guidance was intended to provide a simplified probabilistic framework for use by the staff in identifying potentially risk significant findings in the reactor safety area--either the IE, MS, or BI cornerstones.

When the ROP was initially implemented in April 2000, the staff's efforts to develop the notebooks for each nuclear plant were still in progress. As a result, the draft notebooks that were made available for staff use at initial ROP implementation were considered to be incomplete. By late 2000, the staff had made 44

sufficient progress in the site visits associated with the development of notebooks, that it began to issue the "Revision 0" notebooks to the sites. After issuance of the first Rev. 0 notebooks, the staff identified problems with the accuracy of the notebooks and concluded that benchmarking was needed to confirm the adequacy of the notebooks. Using NRC risk analysts and contractor resources, the staff began its efforts to benchmark the notebooks in April 2001.

In a memorandum dated November 8, 2001, Troy Pruett, Senior Reactor Analyst, Region IV, submitted a differing professional view (DPV) to the Director of the Division of Reactor Safety in Region IV. The DPV expressed concerns about the performance of the SDP Phase 2 analyses. An Ad Hoc Panel, appointed by the Regional Administrator by memorandum dated November 16, 2001, was formed to review the DPV and make appropriate recommendations. The DPV Panel documented its findings in a report to the Region IV Administrator dated January 10, 2002. This report was forwarded to the Director, NRR, for program office consideration and appropriate action. In a memorandum dated February 18, 2002, the Director, NRR informed Mr. Pruett of the results of the review of his DPV. Mr. Pruett expressed several concerns with the results of the DPV review and, in a memorandum to the EDO dated March 15, 2002, recommended an independent review of the concerns in his DPV. Through a memorandum dated April 9, 2002, the EDO convened an Ad Hoc panel to review Mr. Pruett's DPO.

The DPO Panel completed its review and issued conclusions and recommendations in a report dated June 28, 2002. The DPO Panel generally agreed with the overall analysis performed by the DPV panel and its response to Mr. Pruett's recommendations. The DPO Panel found that "NRC management and staff are in the process of addressing many of the Ad Hoc DPV Panel's observations and recommendations in the SDP Improvement Initiative." However, the DPO Panel also recommended that the NRC conduct an independent review of the SDP assessment tools.

Between May and October 2001, the OIG conducted an audit of the SDP. The objectives of the audit, as indicated in the OIG's report (OIG-02-A-1 5) dated August 21, 2002, were to determine whether (1) the SDP is achieving desired results, (2) NRC staff clearly understand the process, and (3) NRC staff are using [the]

SDP in accordance with agency guidance. In its report, OIG concluded that "while the SDP is meeting is objectives and agency staff are using SDP in accordance with guidance, additional refinements are needed." The report provided a number of recommendations, including that the NRC develop an action plan to correct Phase 2 analysis weaknesses or eliminate this portion of the SDP. Objectives in the Plan which address the OIG recommendations are identified by recommendation number. As of September 2004, four recommendations remain resolved but not closed. Next update on the status of the recommendations is due from the staff to the OIG on January 31, 2005.

Proposed Actions: In a memorandum to the Director, NRR dated August 6, 2002, the EDO directed that a plan be developed to address both the DPO Ad Hoc Panel and OIG recommendations. The EDO's memorandum indicated that this "plan shall address the DPO Panel recommendation for an overall objective review of the SDP." The plan developed by the Director, NRR included the formation of the SDP Task Group to conduct an independent review of the SDP.

Consistent with the Charter, the Task Group's review focused on the SDP for the Reactor Safety Strategic Performance Area and, in particular, issues pertaining to the SDP for the Initiating Events (IE), Mitigating Systems (MS) and Barrier Integrity (BI) Cornerstones. As a result, the Task Group did not perform a detailed review of the SDP for the Radiation Safety Performance Area or Safeguards Performance Area.

45

In addition, because the Emergency Preparedness (EP) Cornerstone SDP was not the focus of the DPO Panel Response or OIG Audit Report, and because the relevant EP SDP issues are the focus of other NRC review activities, the Task Group did not emphasize this area in its review. Twenty recommendations of the Task Group are addressed by The Plan Objectives. Fifteen of the recommendations have been completed.

The SDP Improvement Task Action Plan (The Plan) was developed to guide staff efforts aimed at implementing the recommendations developed by the SDPTG and lessons learned since initial implementation of the ROP. The Plan delineates responsible organizations, establishes aggressive completion dates, and provides status updates for each of the specified Plan action items.

Originating Documents: Memorandum from S. Collins to V. McCree dated September 18, 2002, "Significance Determination Process Task Group." (ADAMS Accession No. ML022620580)

Office of Inspector General Audit Report, OIG-02-A-15, "Review of NRC's Significance Determination Process," dated August 21, 2002. (ADAMS Accession No. ML022470372)

Memorandum from Johnson, J.W. to Travers, W.D. dated June 28, 2002, "Differing Professional Opinion (DPO) Concerning the Significance Determination Process." (ADAMS Accession No. ML021830090)

Regulatory Assessment: No adjustment to the current regulatory framework is warranted at this time. The current regulatory framework provides reasonable assurance that operating commercial light-water reactor facilities are safe.

Current Status: N/A.

Contact:

Peter Koltay, DIPM/IIPB/RIS, 415-0213

References:

SECY 99-007 Recommendations for Reactor Oversight Process Improvements.

SECY 99-007A Recommendations for Reactor Oversight Process Improvements (Follow-up to SECY-99-007).

IMC 0609 The Significance Determination Process.

IMC 2515 Light-Water Reactor Inspection Program -Operations Phase.

Status Summary: N/A 46

STEAM GENERATORS TAC Nos. Description Last Update: 12/31/04 M88885 Steam Generator (SG) Integrity Rulemaking Lead Division: DLPM M99432 GL: SG Tube Integrity Supporting Divisions: DE, MA4265 NEI 97-06 DIPM, and DSSA MA5037 SG Action Plan Supporting Office: RES MA5260 DPO on SG Issues MA7147 GSI-163 MA9881 Regulatory Issue Summary - IP2 SG Tube Failure MB0258 SG Action Plan Administration M80553 SG Inspection Program MB0576 Licensee SG Inspection Results Summary Reports & SG Tube Integrity Amendment Review Guidance MB0631 SG Workshop MB0633 OL No. 803 Revisions per SG Action Plan MB0737 IIPB SG Action Plan Activities MB2446 SG Risk Communication MB3794 SG Communication Plan MB7216 SG DPO Followup MB7842/3 Catawba Pilot Plant Application (Fee billable, not added to AGAP total)

MC1 550 NEI 97-06 Review MC2470 SG Tube Integrity & Associated Technical Specifications Item No. Milestone Date Lead Support (TAC No.)

(T=Target)

(C=Complete) 1.1 Issue Regulatory Information 11/03/00 (C) DE (MA9881) Summary on SG Lessons Learned ML010820457 E. Murphy (TG: 8; page 2 of Ref. 2) 1.2 Discuss steam generator action plan 12/20/00 (C) DE (MA4265) and IP2 lessons learned with industry ML010820457 T. Sullivan and other external stakeholders (TG: R. Rothman 2a-2o, 3a, 3b, 4a, 4b, 4c, 8) 1.3 Subsequent to item 2, identify 12/27/00 (C) DLPM DE (MB0258) technical and management leads for ML010820457 R. Ennis K. Karwoski each item and develop initial resource estimates DIPM D. Coe 1.4 Brief management on resource 12/27/00 (C) DLPM DE (MB0258) estimates and invoke PBPM process ML010820457 R. Ennis K. Karwoski as appropriate DIPM

_____ ____ D. Coe 47

Item No. Milestone Date Lead Support (TAC No.)

(T=Target)

(C=Complete) 1.5 Staff review of ACRS 05/11/01 (C) DLPM DE (MA5260) recommendations on DPO and ML011720125 R. Ennis S. Coffin develop detailed milestones and ML011300073 E. Murphy evaluate impact on other action plan milestones. Invoke PBPM process, DSSA as appropriate. (GSI-163 and DPO) S. Long RES J. Muscara 1.6 Determine GSI-163 resolution 05/11/01 (C) DE (MA7147) strategy and revise steam generator E. Murphy action plan milestones, as appropriate (GSI-1 63) 1.7 Determine need to incorporate new 01/24/01 (C) DIPM DE (MB0553) steam generator performance ML010820457 D. Hickman C. Khan indicators into Reactor Oversight E. Murphy Process (page 2 of Ref. 2; TG: 5e, 5f)

DSSA S. Long 1.8 Recommence work on NEI 97-06 01/31/01 (C) DE (MA4265) (page 3 of Ref. 2; TG: 7) ML010820457 E. Murphy 1.9 Review NRC inspection program and, 03/30/01 (C) DE DIPM (MB0553) if necessary, revise guidance to ML010920112 L. Lund inspectors on overseeing facilities DSSA with known steam generator tube S. Long

.____ leakage. (Attachment 3 to Ref. 1) . -

1.10 Reassess the NRC treatment of 04/30/01 (C) DE (MB0576) licensee steam generator inspection ML011220621 S. Coffin results summary reports and ML013020093 conference calls during outages.

Evaluate need for review guidance.

(Attachment 3 to Ref. 1; TG: 6c; page 4 and 5 (top and bottom) of Ref. 1) 48

Item No. Milestone Date Lead Support (TAC No.)

(T=Target)

(C=Complete) 1.11 Review the NRC inspection program (MB0553) and, if necessary, revise guidance to inspectors on overseeing facility eddy current inspection of steam generators. This involves the following major substeps:

a) review and revise the baseline 04/30/01 (C) DE DIPM inspection program. ML011210293 C. Khan DSSA S. Long b.1) review how ISI results/degraded 09/21/01 (C) DSSA DE conditions should be assessed ML012680252 S. Long C. Khan for significance by a risk- DIPM informed SDP and define P. Koltay needed revisions to the SDP b.2) develop and issue draft revision 02/21/02 (C) DIPM DSSA of risk-informed SDP using ML020730318 P. Koltay S. Long information identified in b.1 ML020560366 DE above ML012970361 C. Khan c) review and revise the training DIPM DE program for inspectors E. Kleeh C. Khan c.1) Provide IP training material to 10/11/01 (C)

Regions c.2) Formal training to inspectors 02/01/02 (C)

(Attachment 3 to Ref. 1; TG: 5a, 5b, 5c, 5d, 5f, 6c) 1.12 Determine need for formal written 04/30/01 (C) DE (MB0576) guidance for technical reviewers to ML011220621 S. Coffin utilize in performing steam generator tube integrity license amendment reviews (TG: 5c, 6a) 1.13 Staff provides EDO with update on 05/17/01 (C) DLPM (MB0258) status of action plan (page 8 of ML011720125 R. Ennis Ref. 1) 49

Item No. Milestone Date Lead Support (TAC No.)

(T=Target)

(C=Complete) 1.14 Staff completes review and issues TBD DE (MB7842/3) safety evaluation on pilot plant Note 12 E. Murphy application (NEI 97-06, TG: 2, 3, 4, 7) 1.15 Hold steam generator workshop with 02/27/01 (C) DE (MB0631) stakeholders (page 2 of Ref. 1; page ML010820457 R. Rothman 2 of Ref. 2) 1.16 Staff completes review of generic TBD (T) DRIP DE package and issues model SE for Note 12 K. Kavanagh E. Murphy TSTF in FR for public comments (NEI 97-06) . l 1.17 Publish Notice of Availability of TSTF TBD (T) DRIP in FR (NEI 97-06) Note 12 K. Kavanagh 1.18 Staff briefs the Commission on 05/29/03 (C) K. Karwoski (MA4265) regulatory framework (NEI 97-06, and WITS Item 199400048) 1.19 Issue generic communication related 10/31/01 (C) DE to steam generator operating ML020230299 Z. Fu experience and status of steam generator issues 1.20 Staff issues a Commission Paper on 05/16/03 (C) DE (MA4265) regulatory framework (NEI 97-06, ML023540491 L. Lund and WITS Item 199400048) 1.21 Staff issues a Generic Letter 03/31/05 (T) DE (MC2470) requesting PWR licensees to address Note 12 L. Lund adequacy of their technical specifications to ensure tube integrity between inspections and how bending loads are assessed in their tube integrity evaluations _

50

Item No. Milestone Date Lead Support (TAC No.)

(T=Target)

(C=Complete) 2.1 Evaluate the need for a new 12/05/00 (C) IRO communication protocol with the U.S. ML010460485 F. Congel Secret Service that would cover ML010820457 emergency situations at all NRC licensed facilities (Attachment 3 of Ref. 1) 2.2 Establish NRC web site for Steam 01/16/01 (C) DLPM (MB0258) Generator Action Plan ML010820457 R. Ennis 2.3 Review and revise, as appropriate, 03/23/01 (C) DLPM (MB0258) the policy for project manager ML011020026 R. Ennis involvement with the morning call between the resident inspectors and the region. (Attachments 3 and 4 of Ref. 1) 2.4 Review program requirements for 04/03/01 (C) DIPM (MB0737) routine communications between the ML010890426 T. D'Angelo resident inspectors and local officials based on public interest. Based on weighing current resident inspector responsibilities (e.g., inspection requirements, following up on plant events) against this review, revise program requirements if needed.

(Attachment 3 of Ref. 1) 2.5 Develop, revise, and implement, as 04/03/01 (C) DIPM (MB0737) appropriate, a process for the timely ML010890426 G. Klingler dissemination of technical information to inspectors for inclusion in the inspection program (TG: 5g) 51

Item No. Milestone Date Lead Support (TAC No.)

(T=Target)

(C=Complete) 2.6 Incorporate experience gained from PMAS (MB2446) the IP2 event and the SDP process M. Kotzalas (MB3794) into planned initiatives on risk communication and outreach to the public (TG: 9)

1. Issue NRR input for 01/31/02 (C) incorporation into OEDO initiative ML020590125

2. Address SRM dated 12/26/01 12/24/02 (C)

ML023440202 2.7 Investigate possibility of establishing 06/18/01 (C) DLPM (MB0258) protocol with OIG regarding review of ML011720125 R. Ennis draft reports for factual/contextual errors (page 8 of Ref. 1) 2.8 Review and revise, as appropriate, DLPM (MB0633) the amendment review process, M. Banerjee including concurrence responsibilities, DLPM supervisory oversight, and second- M. Fields round requests for additional information.

a. Issue Q1 LIC-101 08/31/01 (C)

b. Issue procedure for NRR and 02/27/02 (C)

RES interactions ML020580484 (Attachment 3 of Ref. 1; TG: 6b, 6d, 6e; page 6 of Ref. 1) 52

Item No. Milestone Date Lead Support (TAC No.)

(T=Target)

(C=Complete) 3.1 In order to address ACRS comments (MB7216) on current risk assessments, develop a better understanding of the potential for damage progression of multiple steam generator (SG) tubes due to depressurization of the SGs (e.g.,

during a main steam line break (MSLB) or other type of secondary side design basis accident).

(Pgs. 46, 8-12)

(See Notes 4, 5, and 6)

Specific tasks include:

a) Perform thermal-hydraulic (T-H) 12/31/02 (C) RES DSSA calculations and sensitivity studies ML023650132 W. Krotiuk W. Jensen using the 3-D hydraulic component of TRAC-M to assess the loads on the tube support plate and SG tubes during main steam line break (MSLB).

Perform sensitivity studies on code and model parameters including numerics. Develop conservative estimate of loads and evaluate against similar analyses.

b) Perform T-H assessment of flow- 12/31/02 (C) RES DSSA induced vibrations during MSLB. ML023650132 W. Krotiuk W. Jensen Using the T-H conditions calculated during the transient, generate a conservative estimate of flow-induced vibration displacement and frequency assuming steady state behavior.

53

Item No. Milestone Date Lead Support (TAC No.)

(T=Target)

(C=Complete) 3.1 c) Perform additional sensitivity 06/30/03 (C) RES SSA (continued) studies as needed. W. Krotiuk W. Jensen d) Obtain information from existing 12/31/02 (C) RES analyses related to loads and ML030230822 J. Muscara displacements (axial, bending, cyclic) Non-public experienced by SG structures under MSLB conditions.

e) Using information from tasks 3.1a, 12/31/02 (C) RES DE 3.1 b, and 3.1d, estimate upper bound ML030230822 J. Muscara E. Murphy loads and displacements. Non-public f) Estimate crack growth, if any, for a 12/31/02 (C) RES DE range of crack types and sizes using ML030230822 J. Muscara E. Murphy bounding loads from task 3.1e in Non-public addition to the pressure stresses.

Include the effects of TSP movement in these evaluations and any effects from cyclic loads.

g) Estimate the margins to crack 12/31/02 (C) RES DE propagation for a range of crack sizes ML030230822 J. Muscara E. Murphy for MSLB types loads and Non-public displacements in addition to the pressure stress.

h) Based on the margins calculated in 12/31/02 (C) RES DE task 3.1 g over and above the ML030230822 J. Muscara E. Murphy bounding loads, decide if more Non-public refined TH analyses need to be conducted to obtain forces and displacements of structures under MSLB conditions.

54

Item No. Milestone Date Lead Support (TAC No.)

(T=Target)

(C=Compfete) 3.1 1)Conduct tests of degraded tubes 06/30/03 (C) RES DE (continued) under pressure and with axial and ML032080002 J. Muscara E. Murphy bending loads to validate the (Non-public) analytical results from above tasks.

j) Conduct analyses similar to above 06/30/04 (C) RES DE with refined load estimates if ML042720174 J. Muscara E. Murphy necessary.

k) Use information developed in tasks 02/28/05 (T) DSSA DE 3.1 a through 3.1 j to evaluate the S. Long E. Murphy conditional probabilities of multiple RES tube failures for appropriate scenarios J. Muscara in risk assessments for SG tube H. Woods alternate repair criteria (ARC).

3.2 Confirm that damage progression via jet cutting of adjacent tubes is of low enough probability that it can be neglected in accident analyses.

(Pgs. 10-11) (See Notes 3 and 5)

Specific tasks include:

a) Complete tests of jet impingement 12/31/01 (C) RES DE under MSB conditions. ML021910311 J. Muscara E. Murphy b) Conduct long duration tests of jet 12/31/01 (C) RES DE impingement under severe accident ML021910311 J. Muscara E. Murphy conditions.

c) Document results from tasks 3.2a 12/31/01 (C) RES DE and 3.2b. ML021910311 J. Muscara E. Murphy 3.3 When available, use data from the 09/30105 (T) RES DSSA (MB7216) ARTIST program (planned in See Note 2 R. Lee S. Long Switzerland) to develop a better model of the natural mitigation of the radionuclide release that could occur in the secondary side of the SGs.

(Pgs. 12-13) (See Notes 3 and 5) 55

Item No. Milestone Date Lead Support (TAC No.)

(T=Target)

(C=Complete) 3.4 In order to address ACRS criticism of (MB7216) current risk assessments, develop a better understanding of RCS conditions and the corresponding component behavior (including tubes) under severe accident conditions in which the RCS remains pressurized.

(Pgs. 46-47,12-15)

(See Notes 3 and 5)

Specific tasks include:

a) Perform system level analyses to 09/28/01 (C) RES DSSA assess the impact of plant sequence ML012720004 C. Tinkler W. Jensen variations (e.g., pump seal leakage S. Long and SG tube leakage).

b.1) Re-evaluate existing system level 04/12/02 (C) RES DSSA code assumptions and simplifications. D. Bessett W. Jensen S. Long b.2) Following the results from 3.4.a and 3.4.b.1, perform additional 04/01/04 (C) RES DSSA analysis to: include modeling of heat ML040910022 C. Boyd W. Jensen transfer enhancement from radiation (Non-public) heat transfer in the hot leg and steam generator; suppress unphysical numerically driven flows in the calculations; and investigate the sensitivity of calculated results to bypass flows and other key parameters.

c) Examine 1/7 scale data to assess tube to tube temperature variations 08/31/02 (C) RES DSSA and estimate variations for plant D. Bessett W. Jensen scale. S. Long d) Perform more rigorous uncertainty analyses with system level code to 12/31/05 (T) RES DSSA address the uncertainty caused by. Note 13 C. Boyd W. Jensen key governing parameters. S. Long Distribution functions will be developed for key parameters. Peer review.

56

Item No. Milestone Date Lead Support (TAC No.)

(T=Target)

L_ (C=Complete) 3.4 e) Examine SG tube severe accident (continued) T-H conditions using computational fluid dynamics (CFD) methods. This includes the following:

e.1) Benchmark CFD methods 08/31/01 (C) RES DSSA against 1/7 scale test data. NUREG 1781 C. Boyd W. Jensen ML033140399 S. Long e.2) Perform full scale plant 03/28/02 (C) RES DSSA calculations (hot leg and SG) for a 4 NUREG 1788 C. Boyd W. Jensen loop Westinghouse design. Evaluate ML041820075 S. Long scale effects. (Non-public) e.3) Perform plant analysis to address 12/30/02 (C) RES DSSA the effects on inlet plenum mixing NUREG 1788 C. Boyd W. Jensen resulting from tube leakage and hot ML041820075 S. Long leg orientation (CE design impact). (Non-public) f) Examine the uncertainty in the T-H 03/31/05 (T) RES DSSA conditions associated with core melt Note 13 C. Boyd W. Jensen progression. S. Long g) Perform experiments to develop 03/31/03 (C) RES DSSA data on inlet plenum mixing impacts See Note 15 D. Bessett W. Jensen due to SG tube leakage and hot leg/ S. Long inlet plenum configuration.

h) Perform a systematic examination of the alternate vulnerable locations in the RCS that are subject to failure due to severe accident conditions.

This includes the following:

h.1) Evaluate the creep failure of TBD (T) RES DE primary system passive components See Note 18 J. Page E. Murphy such as pressurizer surge line and DSSA the hot leg taking into account the S. Long material properties of the base metal, welds, and heat affected zones in the presence of residual and applied stresses, in addition to the pressure stress, and the presence of flaws.

57

Item No. Milestone Date Lead Support (TAC No.)

Cr=Target)

- (C=Complete) 3.4 h.2) Evaluate the failure of active TBD (T) RES DE (continued) components such as PORVs, safety Note 18 J. Page E. Murphy valves, and bolted seals based on DSSA operability and "weakest link" S. Long considerations for these components.

h.3) Conduct large scale tests if 11/30/05 (T) RES DE needed. J. Page E. Murphy DSSA S. Long I) Use existing international data and 05/28/04 (C) RES DSSA develop analyses for predicting leak J. Muscara S. Long rates of degraded tubes in restricted ML042720174 DE areas under design basis and severe E. Murphy accident conditions.

j) Put the information developed in TBD (T) DSSA DE task 3.4i into a probability distribution Note 17 S. Long E. Murphy for the rate of tube leakage during RES severe accident sequences, based on J. Muscara the measured and regulated parameters for ARCs applied to flaws in restricted places (e.g., drilled-hole TSPs and the unexpanded sections of tubes in tube sheets).

k) Integrate information provided by tasks 3.4a through 3.4j and 3.5 to TBD (T) DSSA DE address ACRS criticisms of risk Note 17 S. Long E. Murphy assessments for ARCs that go RES beyond the scope and criteria of J. Muscara GL 95-05 (e.g., ARCs that credit C. Boyd Indications restricted against burst") H. Woods as well as dealing with other SG tube integrity and licensing issues (e.g.,

relaxation of SG tube inspection requirements).

58

Item No. Milestone Date Lead Support (TAC No.)

(T=Target)

(C=Complete) 3.5 Develop improved methods for (MB7216) assessing the risk associated with SG tubes under accident conditions.

(Pgs. 47, 16-20) (See Note 5)

Specific tasks include:

a) Development of an integrated 04/01/02 (C) RES DSSA framework for assessing the risk for ML020910624 H. Woods S. Long the high-temperature/high-pressure accident scenarios of interest.

b) Issue report describing improved 06/28/03 (C) methods and appropriate treatment of ML031810770 RES DSSA uncertainty for identifying severe H Woods S. Long accident scenarios that lead to challenges of the reactor coolant pressure boundary.

c) Develop logic framework for 04/06/04 (C) RES DSSA improved PRA models of the ML041400397 H. Woods S. Long scenarios identified above, including (Non-public) the impact of operator actions.

d) Using the 3.5(b) methods and (C) logic framework, identify scenarios, TBD (T) RES DSSA calculate the frequency of See Note 16 H. Woods S. Long containment bypass events at an example plant, make indicated method improvements, and document the improved methods and results.

59

Item No. Milestone Date Lead Support (TAC No.)

(T=Target)

(C=Complete) 3.5 e) Extend the 3.5(b) methods and TBD (T) RES DSSA (continued) (C) model logic to include CE plants, See Note 16 H. Woods S. Long and document them.

f) Extend the 3.5(b) methods and TBD (T) RES DSSA (C) model logic to include See Note 16 H. Woods S. Long consideration of external events as initiators, and low power and shutdown as initial conditions, and document them.

g) Extend the 3.5(d), (e), and TBD RES DSSA (f) improved methods and logic to See Note 16 H. Woods S. Long include consideration of core damage sequences initiated by secondary depressurization events (such as MSLB design basis accident scenarios) that induce tube rupture.

3.6 To address an ACRS report 12/31/01 (C) RES DE conclusion that improvements can be ML021910311 J. Muscara E. Murphy made over the current use of a constant probability of detection (POD) for flaws in SG tubes, RES has recently completed an eddy current round robin inspection exercise on a SG mock-up as part of NRC's research to independently evaluate and quantify the inservice inspection reliability for SG tubes. This research has produced results that relate the POD to crack size, voltage, and other flaw severity parameters for stress corrosion cracks at different tube locations using industry qualified teams and procedures. Complete analysis of research results and prepare topical report to document the results.

(Pgs. 47, 33) 60

Item No. Milestone Date Lead Support (TAC No.)

(T=Target)

(C=Complete) 3.7 Assess the need for better leakage 04/26/03 (C) DE RES (MB7216) correlations as a function of voltage ML031150674 J. Tsao J. Muscara for 7/8" SG tubes.

(Pgs. 48, 28-29) (See Note 5) 3.8 Develop a program to monitor the 01/03/02 (C) DE (MB0258) prediction of flaw growth for ML020070081 J. Tsao systematic deviations from expectations.

(Pg. 48) (See Note 5) 3.9 Develop a more technically defensible DSSA (MB7216) position on the treatment of radio M. Hart nuclide release to be used in the safety analyses of design basis events.

(Pgs. 48, 38-44) (See Note 5)

Specific tasks include:

a) Assess Adams and Atwood and 08/09/01 (C)

Adams and Sattison spiking data with respect to the ACRS comments.

b) Based upon the assessment TBD (T) performed in task 3.9a, develop a Note 11 response to the ACRS comments.

c) Publish in the Federal Registerfor TBD (T) public comment, the response to Note 11 ACRS' comments.

d) Complete review of public TBD (T) comments. Note 11 e) Based upon task 3.9d, determine if TBD (T) additional work needs to be Note 11 performed.

61

Item No. Milestone Date Lead Support (TAC No.)

(r=Target)

(C=Complete) 3.10 To address concerns in the ACRS (MB721 6) report regarding our current level of understanding of stress corrosion cracking, the limitations of current laboratory data, the difficulties with using the current laboratory data for predicting field experience (crack initiation, crack growth rates), and the notion that crack growth should not be linear with time while voltage growth is, the following tasks will be performed:

(Pgs. 20-29)

(See last sentence in Note 3)

Specific tasks include:

a) Conduct tests to evaluate crack 12/31/05 (T) RES DE initiation, evolution, and growth. J. Muscara E. Murphy Tests to be conducted under prototypic field conditions with respect to stresses, temperatures and environments. Some tests will be conducted using tubular specimens.

b) Using the extensive experience on 12/31/06 (T) RES DE stress corrosion cracking in operating J. Muscara E. Murphy SGs, and results from laboratory testing under prototypic conditions, develop models for predicting the cracking behavior of SG tubing in the operating environment.

c) Based on the knowledge 12/31/05 (T) RES DE accumulated on stress corrosion J. Muscara E. Murphy cracking behavior and the properties of eddy current testing, attempt to explain the observed relationship between changes in eddy current signal voltage response and crack growth.

62

Item No. Milestone Date Lead Support (TAC No.)

(T=Target)

(C=Complete) 3.11 In order to resolve GSI 163, it is 12/31/05 (T) DLPM DSSA necessary to complete the work DE S. Long associated with tasks 3.1 through 3.5 E. Murphy and 3.7 through 3.9. Upon completion of those tasks, develop detailed milestones associated with preparing a GSI resolution document and obtaining the necessary approvals for closing the GSI, including ACRS acceptance of the resolution. (See Note 9) 3.12 Develop outline and a detailed 12/31/05 (T) DE DSSA schedule for completing DG 1073, E. Murphy S. Long "Plant Specific Risk-Informed Decision Making: Induced SG Tube Rupture (See Note 9)

Notes:

1. For SG Action Plan milestones associated with the SG DPO (i.e., Item Nos. 3.1 - 3.11), the page numbers referenced in the milestone description indicate the source of the milestone as described in ACRS Report NUREG-1740, "Voltage-Based Alternative Repair Criteria." The ACRS report was included as an enclosure to a memorandum from D. Powers to W. Travers dated February 1, 2001 (Accession No. MLO010780125).

2. NRC has entered into an agreement in April 2003 with Paul Scherrer Institute (PSI) of Switzerland, to participate in the ARTIST program. Testing is to commence in 2004 and is scheduled to be complete in 2007. Some preliminary experimental data from the initial phase of testing will be available in 2004.

3. The work described in this milestone is related, in part, to previously planned work associated with an NRR User Need request dated February 8, 2000 (Accession No. ML003682135), and the associated RES response to the request dated September 7, 2000 (Accession No. ML003714399). In addition, portions of this work were undertaken on an anticipatory basis by RES.

4. The work described in this milestone is related, in part, to previously planned work associated with GSI 188, "Steam Generator Tube Leaks/Ruptures Concurrent with Containment Bypass."

5. The work described in this milestone is related, in part, to previously planned work associated with GSI 163, "Multiple Steam Generator Tube Leakage."

63

6. The thermal-hydraulic analyses (items 3.1 a through 3.1 c) will provide input into the tube integrity analyses (items 3.1 d through 3.1j) on an on-going basis. The end dates for these two areas coincide because of the close integration between these two RES efforts. Also, the end dates reflect the target date for the final report documenting the RES findings.

7. Item Nos. 1.1 through 2.8 in the above table were developed from Attachment 1 of a memorandum from J. Zwolinski, J. Strosnider, B. Boger and G. Holahan to B. Sheron and R. Borchardt dated March 23, 2001 (Accession No. ML010820457). That memorandum provided a revision to the Steam Generator Action Plan that was originally issued via a memorandum from B. Sheron and J. Johnson to S. Collins dated November 16, 2000 (Accession No. ML003770259).

8. Item Nos. 3.1 through 3.11 in the above table were developed from Attachment 1 of a memorandum from S. Collins and A. Thadani to W. Travers dated May 11, 2001 (Accession No. ML011300073).

That memorandum provided a revision to the Steam Generator Action Plan as requested by a memorandum from W. Travers to S. Collins and A. Thadani dated March 5, 2001 (Accession No. ML010670217).

9. The completion date assumes need for large scale test.

10. The ADAMS accession no. listed under "Date" is the closure document.

11. The scope of the work is being re-evaluated. In SECY-04-0156, dated August 27, 2004, Iodine Spiking Phenomena was identified as candidate generic safety issue (GSI) 197 with the Office of Nuclear Regulatory Research (RES) listed as the lead organization. Initial screening of the candidate GSI is to be completed by January 2005.

12. The NRC received the steam generator license amendment submittal for a lead plant (Catawba) on February 25, 2003, and the generic submittal as a Technical Specification Task Force (TSTF) Traveler on March 14, 2003. Extensive discussions were held with the industry regarding the structural integrity performance criterion issue (i.e., what is the appropriate safety factor to apply to bending loads and the methodology for determining the effects of bending loads on flawed steam generator tubing). After several meetings with the industry, the staff reached a tentative agreement on the wording of the structural integrity performance criterion. In the interim, Farley made a submittal in June 2004. The staff has approved the changes to the Farley SG TS on September 10, 2004, while review of the Catawba application is ongoing. The staff is in the process of converting the Farley SG technical specification safety evaluation (SE) into the model (generic) SE for the TSTF. The staff plans to issue the draft consolidated line item improvement process (CLIIP) in the Federal Registerfor public comments by the end of February 2005 after the industry submits a revision to the TSTF in January 2005. In the meantime, the staff has also issued in the Federal Registera generic letter (GL 2004-xx, Steam Generator Tube Integrity and Associated Technical Specifications) for a 60 day comment period. This GL requested licensees (1) to discuss the adequacy of their steam generator tube integrity program and their plans for modifying their TS to ensure they are representative of their program and (2) to discuss how bending loads are assessed in their evaluations of tube integrity. The licensees that have adopted the new version of the TS will not be required to respond to the GL.

The public comment period on the draft GL expired on December 6, 2004, and the staff is currently reviewing the comments. One of the comments requested that the NRC withhold issuing the GL until the generic SE is issued for the TSTF. The staff will consider this and other comments in finalizing the GL.

64

13. This task has been delayed so that resources could be used to address emerging issues raised by the PRA analysis. In addition, contractor resources have been temporarily prioritized towards completion of more critical time sensitive work. December 31, 2005, is the currently estimated target date for milestone 3.4.d pending RES management approval. Although milestone 3.4.f is being completed as planned in the RES Operating Plan, the core melt progression will be revisited under 3.4.d during the full evaluation of uncertainty.

14. Note 14 no longer exists.

15. This milestone was not performed as evaluation of the cost to perform experiments that would improve upon the Westinghouse experiments showed the cost to be prohibited. CFD analysis provided better information than possible experiments at a very small fraction of the cost. Hence, the objective was satisfied by the completion of milestone 3.4.e.2.

16. Lessons learned from the work completed so far necessitated several modifications and additions to the tasks, milestones, and target completion dates that are being formalized in the RES operating plan and in this SG Action Plan. Scheduled completion date for item 3.5.d thru g will be provided when the present workscope is expanded.

17. The results from this item feed into the task for calculating the severe accident induced steam generator containment bypass probabilities. New completion dates need to be developed based on scheduled completion of 3.4 and 3.5 milestones.

18. Additional analyses will need to be performed to support the development of a robust probabilistic risk assessment.

==

Description:==

Steam generator tube integrity issues continue to arise. As a result, many organizations within the NRC have evaluated portions of the regulatory process associated with steam generator tube integrity and have made some insightful observations and/or recommendations. To ensure safety from a steam generator tube integrity standpoint is maintained, that public confidence in the steam generator tube integrity area is improved, and the NRC and stakeholder resources are effectively and efficiently utilized, the steam generator action plan was developed. The action plan is intended to direct and monitor the NRC's effort in this area and to ensure the issues are appropriately tracked and dispositioned. The action plan is also intended to ensure the NRC's efforts result in an integrated steam generator regulatory framework (license review, inspection and oversight, research, etc.) which is effective, efficient, and realistic.

This plan consolidates numerous activities related to steam generators including: 1) the NRC's review of the industry initiative related to steam generator tube integrity (i.e., NEI 97-06); 2) GSI-1 63 (Multiple Steam Generator Tube Leakage); 3) the NRC's Indian Point 2 (1P2) Lessons Learned Task Group recommendations; 4) the Office of the Inspector General (OIG) report on the IP2 steam generator tube failure event; and 5) the differing professional opinion (DPO) on steam generator issues. The plan does 65

not address plant-specific reviews or industry proposed modifications to the Generic Letter 95-05 (voltage-based tube repair criteria) methodology. The plan also includes non-steam generator related issues that arose out of recent steam generator related activities (e.g., Emergency Preparedness issues from the OIG report). The milestone table shown above is organized as follows:

- Item Nos. 1.1 through 1.21: SG-related issues (not including the DPO-related issues);

- Item Nos. 2.1 through 2.8: Non-SG related issues; and

- Item Nos. 3.1 through 3.11: DPO-related issues.

Historical

Background:

The NRC originally planned to develop a rule pertaining to steam generator tube integrity. The proposed rule was to implement a more flexible regulatory framework for steam generator surveillance and maintenance activities that allows a degradation specific management approach. The results of the regulatory analysis suggested that the more optimal regulatory approach was to utilize a generic letter. The NRC staff suggested, and the Commission subsequently approved, a revision to the regulatory approach to utilize a generic letter. In SECY-98-248, the staff recommended to the Commission that the proposed GL be put on hold for 3 months while the staff works with NEI on their NEI 97-06 initiative. In the staff requirements memorandum dated December 21, 1998, the Commission did not object to the staff's recommendation. In late 1998 and 1999 the NRC and industry addressed NRC technical and regulatory concerns with the NEI 97-06 initiative, and on February 4, 2000, NEI submitted the generic licensing change package for NRC review. The generic licensing change package included NEI 97-06, Revision 1, proposed generic technical specifications, and a model technical requirements manual section. SECY-00-0078 outlines the staff's proposed review process associated with the revised steam generator tube integrity regulatory framework described in NEI 97-06. This review process was subsequently revised as described in SECY-03-0080 (see Note 12).

Originating Document: Memorandum from B. Sheron/J. Johnson to S. Collins dated November 16, 2000, "Steam Generator Action Plan" (Accession No. ML003770259).

Regulatory Assessment: The current regulatory framework provides reasonable assurance that operating PWRs are safe. Improvements to the regulatory framework are being pursued through the NEI 97-06 initiative.

Current Status:

- November 1, 2000 Issuance of Indian Point 2 Steam Generator Tube Failure Lessons-Learned Report" via memorandum from W. Travers to the Commission (Accession No. ML003765272).

- November 3, 2000 Issuance of "Staff Review of OIG Report on the NRC's Response to the Steam Generator Tube Failure at Indian Point 2 and Related Issues" via memorandum from W. Travers to the Commission (Accession No. ML003753067).

- November 16, 2000 Issuance of "Steam Generator Action Plan" via memorandum from B. Sheron/J. Johnson to S. Collins (Accession No. ML003770259).

- February 1, 2001 ACRS Ad Hoc Subcommittee report related to SG DPO issued (NUREG-1740).

- May 11, 2001 Issuance of a memorandum providing a revision to the SG Action Plan to address the issues related to the DPO on SG tube integrity issues (Accession No. ML011300073).

66

- September 26, 2001 Staff briefing of ACRS subcommittee on Materials and Metallurgy regarding SG action plan status.

- September 26, 2001 Staff briefing of ACRS Subcommittee on Materials and Metallurgy on SG action plan.

- October 4, 2001 Staff briefing of ACRS full-committee on SG action plan status.

- October 18, 2001 ACRS letter to the Chairman documenting their comment on staff action plan to address the SG DPO (ML012960166).

- November 29, 2001 Staff briefing of ACRS Subcommittee on Materials and Metallurgy on NEI 97-06.

- December 3, 2001 Staff briefing of the Commission on the status of SG action plan.

- December 06, 2001 Staff briefing of ACRS on NEI 97-06.

- May 16, 2003 Issuance of SECY-03-0080, "Steam Generator Tube Integrity (SGTI) - Plans for Revising the Associated Regulatory Framework."

- May 29, 2003 Staff briefing of the Commission on the status of SG Regulatory Framework Modifications. An industry briefing preceded the staff briefing.

- February 3-5, 2004 Staff briefing of the joint ACRS Subcommittee on Materials/Metallurgy and ThermaVHydraulics, and the Full Committee on SG DPO related action items.

- May 21, 2004 ACRS letter to the EDO documenting their comment on staff action plan to address the SG DPO (ML041420237).

- August 25, 2004 Response to ACRS from the EDO on their comments on staff action plan to address the SG DPO (ML042400055)

NRR Technical Contacts: Louise Lund, DE/EMCB, 415-3248 Doug Coe, DIPM/IIPB, 415-2040 Steve Long, DSSA/SPSB, 415-1077 NRR Lead PM: Maitri Banerjee, DLPM, 415-2277 RES Contacts: Joe Muscara, RES, 415-5844 James Davis, 415-6987 67

DAVIS-BESSE LESSONS LEARNED TASK FORCE RECOMMENDATIONS REGARDING STRESS CORROSION CRACKING TAC No. Description MB2916 Non plant-specific activities for Last Update: 12/31/04 Bulletin 2001-01 Lead Division: DLPM MB3567 VHP Action Plan (Coordination Supporting Divisions: DE, DSSA, and Administration) DIPM, & DRIP MB3954 Development of CRDM NUREGs Supporting Offices: RES & Regions (Bulletin 2001 -01)

MB4495 Lead PM Activities for Bulletin 2002-01 MB4603 Non plant-specific activities for Bulletin 2002-01 MB5465 Lead PM Activities for Bulletin 2002-02 MB6218 Inspection TI for Bulletin 2002-02 MB6220 Review of NEI/MRP Crack Growth Rate Report (MRP-55)

MB6221 Development of Alternate (to ASME Code)

RPV Head and VHP Inspection Requirements MB6222 Review of NEI/MRP RPV Head and VHP Inspection Plan (MRP-75)

MB7182 Orders for Interim Inspection Guidelines MB9522 Review of Bulletin 2002-01 Responses MB8915 Generic Activities for Lower Head Inspection MB9891 Develop Bulletin 2003-02 MC0590 Develop Technical Issues Related to Incorporating RCPB Inspection Requirements into 50.55a MC1036 Develop/Revise Inspection Guidance for ISI and BACC Milestone Date Lead Support (T=Target)

(C=Complete)

Part I - Reactor Pressure Vessel Head Inspection Requirements

1. Collect and summarize information available 03/04 (C) RES/DET DE worldwide on Alloy 600, Alloy 690 and other ML040920026 nickel based alloy nozzle cracking for use in evaluation of revised inspection requirements.

[LLTF 3.1.1 (1)-High ]

2. Critically evaluate existing SCC models with 07/03 (C) RES/DET DE respect to their continuing use in the ML032461221 susceptibility index. ML032461224

[LLTF 3.1.4(1)-Medium]

68

Milestone Date Lead Support (T=Target)

(C=Complete)

3. a. Complete initial evaluation of individual 05/04 (C) DE DLPM plant inspections in response to Bulletins and ML041560306 Regions Orders.

b. Continue to review future inspection results Ongoing DE DLPM until permanent guidelines are issued. Regions

4. Incorporate Order EA-03-009 requirements Note (2) into 10 CFR 50.55a

1. Develop technical basis 04/04 (C) DE DRIP ML040920628 ML040920638

2. Develop rulemaking plan 07/04 (C) DRIP DE

3. Commission decision 08/04 (C)

ML042190072

5. Monitor and provide input to industry TBD DE RES/DET efforts to develop revised RPV Head Note (1) DSSA inspection requirements (ASME Code Regions Section Xl). Industry

[LLTF 3.3.4(8)-High

6. Participate in meetings and establish Ongoing DE RES/DET communications with appropriate DLPM stakeholders (e.g., MRP, ASME). DRIP

[LLTF 3.3.4(8)-High] DSSA industry

7. Review and evaluate revised ASME Code TBD DE RES/DET requirements when issued. Note (1)

[LLTF 3.3.4(8)-High]

8. If revised ASME Code requirements are TBD DE DRIP acceptable, establish schedule to Note (1) DIPM incorporate by reference into DSSA 10 CFR 50.55a. RES/DET

[LLTF 3.3.4(8)-High] industry public

9. Publish a NUREG report summarizing 03/05 (T) RES/DET DE findings from Part I, Items 1 and 2, and Part II, Item 1.

69

Milestone Date Lead Support (T=Target)

(C=Complete)

10. Propose a course of action and 10/04 (C) DE RES/DET implementation schedule to address the ML043010675 results of the analysis of Part I, item 1, and Part II, item 1

[LLTF 3.1.1(1)-High]

Part II - Boric Acid Control

1. Collect and summarize information 10/04 (C) RES/DET DE available worldwide on boric acid corrosion ML043000274 of pressure boundary materials for use in evaluation of revised inspection requirements.

[LLTF 3.1.1 (1)-High]

2. a. Evaluate individual plant responses to 06/03 (C) DE DLPM Bulletin 2002-01 regarding Boric Acid ML031760568 Inspection Programs (60-day responses and necessary follow-up)

b. Issue public document to summarize 07/03 (C) DE DLPM evaluation of plant responses. ML032100653 DRIP

3. Participate in meetings and establish Ongoing DE RES/DET communications with appropriate DLPM stakeholders (e.g.,MRP, ASME). DRIP DSSA industry

4. Evaluate need to take additional regulatory 06/03 (C) DE DLPM actions and determine appropriate ML031760568 DRIP regulatory tool(s). DIPM DSSA Regions

5. Issue Bulletin 2003-02 on Reactor Vessel 08/03 (C) DE DLPM Lower Head inspection ML032320153

6. Develop milestones for additional 07/03 (C) DE DLPM regulatory actions, as necessary. DSSA DRIP 70

Milestone Date Lead Support (T=Target)

(C=Complete)

7. Complete and evaluate the results of 06/06 (T) DE RES ongoing research on materials degradation, engage external stakeholders and develop a plan to implement a proactive approach to manage degradation of the RCPB.

8. Review and evaluate the adequacy of 01/05 (T) DE RES/DET revised ASME Code Requirements for Note (1)

Pressure Testing/Leakage Evaluation being developed by the ASME Code,Section XI, Task Group on Boric Acid.

Part IlIl - Inspection Programs

1. Develop inspection guidance or revise 06/04 (C) DIPM DE existing guidance to ensure that VHP Regions nozzles and the RPV head area are periodically reviewed by the NRC during licensee ISI activities. [LLTF 3.3.4(3)-High]

2. Develop inspection guidance that provides 06/04 (C) DIPM DE for timely, periodic inspection of PWR plant Regions BACC programs.

[LLTF3.3.2(1 )-High]

3. a. Develop inspection guidance for 06/04 (C) DIPM DE assessing the adequacy of PWR plant RES/DET BACC programs (implementation Regions effectiveness, ability to identify leakage, adequacy of evaluation of leaks). [LLTF 3.2.2(1)-High]

b. Perform follow-up evaluation of 05/05 (T) DIPM DE inspection guidance and licensee RES/DET program acceptability after conducting Regions inspections for approximately one year.

Notes: (1) Milestone dates are dependent upon issuance of industry proposals.

(2) Requirements for inspection of only the upper head will be the subject of this rulemaking.

71

==

Description:==

The reactor vessel head (RVH) degradation found at Davis-Besse, along with other documented incidences of circumferential cracking of vessel head penetration (VHP) nozzles, have prompted the staff to question the adequacy of current RVH and VHP inspection programs that rely on visual examinations as the primary inspection method. Also, the failure to adequately address indications of boric acid leakage at Davis-Besse raised questions as to the efficacy of industry boric acid control (BACC) programs. Finally, review of the Davis-Besse event identified deficiencies in the NRC inspection programs.

Historical

Background:

In March 2002, while conducting inspections in response to Bulletin 2001-01, the Davis-Besse Nuclear Power Station identified three CRDM nozzles with indications of axial cracking, which were through-wall, and resulted in reactor coolant pressure boundary leakage. During the nozzle repair activities, a 7 inch by 4-to-5 inch cavity on the downhill side of nozzle 3, down to the stainless steel cladding was identified. The extent of the damage indicated that it occurred over an extended period and that the licensee's programs to inspect the RPV head and to identify and correct boric acid leakage were ineffective.

One of the NRC follow-up actions to the Davis-Besse event was formation of a Lessons Learned Task Force (LLTF). The LLTF conducted an independent evaluation of the NRC's regulatory processes related to assuring reactor vessel head integrity in order to identify and recommend areas of improvement applicable to the NRC and the industry. A report summarizing their findings and recommendations was published on September 30, 2002. The report contains several consolidated lists of recommendations.

The LLTF report was reviewed by a Review Team (RT), consisting of several senior management personnel appointed by the Executive Director for Operations (EDO). The RT issued a report on November 26, 2002, endorsing all but two of the LLTF recommendations, and placing them into four overarching groups. On January 3, 2003, the EDO issued a memo to the Director, NRR, and the Director, RES, tasking them with developing a plan for accomplishing the recommendations. This action plan addresses the recommendations in the "Assessment of Stress Cracking" grouping of the RT report. The LLTF recommendations are listed in the attached Table 1, and have been identified under the appropriate milestone(s).

Proposed Actions: The staff is interacting with all PWR licensees, the American Society of Mechanical Engineers (ASME), the Electric Power Research Institute (EPRI) Materials Reliability Program (MRP), and other external stakeholders in addressing the issues discussed above. This action plan includes milestones aimed at guiding the NRC and industry to effectively manage RVH degradation and BACC.

Throughout the implementation of this action plan, the NRC will establish the necessary communications mechanisms to ensure that the NRC, the industry, and all stakeholders are informed and sharing the same information. This will be accomplished through public meetings, technical working groups, ACRS briefings, and web site postings, as appropriate.

The Part I milestones deal with development of improved inspection requirements for the RPV head and VHP nozzles. Interim inspection guidelines for the RPV upper head have been issued via Order EA-03-009 and associated temporary inspection guidelines (TI-1 50) have been issued for use by NRC inspectors.

These will be updated as needed based on inspection results. The staff will monitor and assess the adequacy of revisions to the ASME Boiler and Pressure Vessel Code regarding RPV head inspection, which will be based on the inspection program developed by the EPRI MRP. If the revised ASME Code requirements are acceptable, based on the staff's technical evaluations, the NRC will initiate action to incorporate them by reference in a revision to 10 CFR 50.55a.

72

The Part II milestones evaluate whether industry BACC programs are meeting NRC expectations and whether additional inspection guidance should be issued. First, the staff will establish a technical basis for BACC program requirements through ongoing and planned research programs. This will include evaluation of boric acid events in past reports and in responses to Bulletin 2002-01, and studies of rates of reactor pressure boundary materials in boric acid solutions. The staff is also monitoring development of revised ASME Code requirements by the Section Xl Task Group on Boric Acid . If the staff determines that additional interim guidelines are needed prior to issuance of the revised Code requirements, they will be issued by an appropriate regulatory tool. When the ASME Code requirements are revised, the NRC will initiate action to endorse them, if acceptable. If the revised ASME code requirements cannot be made acceptable to the NRC, then alternate requirements would have to be developed and implemented by an appropriate regulatory tool. Based on the leaks discovered in lower vessel head penetrations at South Texas Project, the staff issued Bulletin 2003-02 regarding RPV lower head inspections. Associated temporary inspection guidelines (TI-1 52) were issued for use by NRC inspectors. The staff will complete and evaluate the results of ongoing research on materials degradation, engage external stakeholders and develop a plan to implement a proactive approach to manage degradation of the RCPB.

The Part IlIl milestones address the LLTF findings that the NRC inspection guidelines did not provide effective oversight of licensee RPV head inspection and BACC programs. Revised guidelines for these activities will be developed. Throughout the process of establishing new requirements, existing NRC inspection procedures would be evaluated to verify whether they adequately address the revised requirements, and would be updated as needed.

Originating Documents:

Memorandum from Travers, W.D. to Collins, S. and Thadani, A. C., dated January 3, 2003, "Actions Resulting From The Davis-Besse Lessons Learned Task Force Report Recommendations." (ADAMS Accession No. ML023640431)

Memorandum from Paperiello, C.J. to Travers, W.D., dated November 26, 2002, "Senior Management Review of the Lessons-Learned Report of the Davis-Besse Nuclear Power Station Reactor Pressure Vessel Head." (ADAMS Accession No. ML023260433)

Memorandum from Howell, A.T. to Kane, W.F., dated September 30, 2002, "Degradation of the Davis-Besse Nuclear Power Station Reactor Pressure Vessel Head Lessons-Learned Report."

(ADAMS Accession No. ML022740211)

Regulatory Assessment: The current method for managing PWSCC in the VHP nozzles of U.S. PWRs is dependent on the implementation of inspection methods intended to provide early detection of degradation of the reactor coolant pressure boundary. Title 10, Section 50.55a(g)(4) of the Code of Federal Regulations requires, in part, that ASME Code Class 1, 2, and 3 components must meet the inservice inspection requirements of Section Xl of the ASME Boiler and Pressure Vessel Code throughout the service life of a boiling or pressurized water reactor. Pursuant to Inspection Category B-P of Table IWB-2500-1 to Section Xl of the ASME Boiler and Pressure Vessel Code, licensees are required to perform VT-2 visual examinations of their vessel head penetration nozzles and reactor vessel heads once every refueling outage for the system leak tests, and once an inspection interval for the hydrostatic pressure test.

73

Based on the experience with the VHP nozzle cracking phenomenon, the VT-2 visual examination methods required by the ASME Code for inspections of VHP nozzles do not provide reasonable assurance that leakage from a through-wall flaw in a nozzle will be detected. The VT-2 visual examination methods specified by the ASME Code are not directed at detecting the very small amounts of boric acid deposits, e.g., on the order of a few grams, that have been associated with VHP nozzle leaks in operating plants. In addition, the location of thermal insulating materials and physical obstructions may prevent the VT-2 visual examination methods from identifying minute amounts of boric acid deposits on the outer surface of the vessel head. Specifically, Paragraph IWA-5242 of Section Xl of the ASME Boiler and Pressure Vessel Code does not require licensees to remove thermal insulation materials when performing ASME VT-2 visual examinations of reactor vessel heads. Cleanliness of reactor vessel heads during the examinations, which is critical for visual examination methods to be capable of distinguishing between boric acid residues that result from VHP nozzle leaks and those residues that result from leaks in other reactor coolant system components, is not addressed by the ASME Code.

Based on knowledge obtained from evaluation of the Davis-Besse event, and information provided from PWR licensees in response to Bulletins 2001-01, 2002-01 and 2002-02, the NRC issued an Order to all PWR plants establishing enhanced inspection requirements on an interim basis, which will provide adequate assurance of safe plant operation until permanent requirements are established and promulgated.

Current Status: Part I activities included continued monitoring of outage inspection results, follow-up with plants discovering defects, and evaluation of requests for relaxation from First Revised Order EA-03-009.

The staff evaluated the existing SCC models and determined that they are acceptable for use in prioritizing RPV head inspections. The report is publicly available in ADAMS.

The staff collected information on Alloy 600, Alloy 690 and other nickel-based alloy nozzle cracking and issued a summary report for internal use. The report is publicly available in ADAMS.

The staff developed a rule plan to incorporate the inspection requirements for the RPV upper head into 10 CFR 50.55a. This was submitted for Commission approval in July 2004. The Commission decided not to proceed with this rulemaking and directed the staff to continue to work with the industry to incorporate revised inspection requirements into the ASME code (SRM-SECY-04-0115, August 6, 2004).

In Part II activities, the review and evaluation of licensee responses to Bulletin 2002-01 regarding BACC have been completed. A summary of the evaluation was published in RIS 2003-13. Based on this review and the discovery of leakage on vessel bottom penetrations at South Texas Project, Bulletin 2003-02 was issued.

The staff collected information on available worldwide operating experience on boric acid corrosion of pressure boundary materials. The report is publicly available in ADAMS. This information and the information previously collected on nozzle cracking will be issued in a NUREG. The NUREG will also include the staff evaluation of the SCC models.

Using the information collected on boric acid corrosion and the information previously collected regarding Alloy 600, Alloy 690 and other nickel-based alloy nozzle cracking, the staff is also considering a proposed course of action and an implementation schedule to address LLTF 3.1.1 (1).

74

In Part IlIl activities, inspection procedure revisions addressing RPV head inspection and boric acid corrosion control programs were issued.

Contacts:

NRR Lead PM: Brendan Moroney, DLPM, 415-3974 NRR/DE Lead

Contact:

William Bateman, EMCB, 415-2795 NRR/DE Technical Contacts: William Koo, EMCB, 415-2706 Edmund Sullivan, EMCB, 415-2796 RES Technical

Contact:

William Cullen, DET/MEB, 415-6754 NRR/DIPM Lead Contacts: Stuart Richards, IIPB, 415-1257 Terrence Reis, IROB, 415-3281

References:

First Revised Order EA-03-009 establishing interim inspection requirements for reactor pressure vessel heads at pressurized water reactors, February 20, 2004.

NRC Bulletin 2003-02, "Leakage From Reactor Pressure Vessel Lower Head Penetrations And Reactor Coolant Pressure Boundary Integrity," August 21, 2003.

NRC Regulatory Issue Summary 2003-13, "NRC Review of Responses to Bulletin 2002-01."

Order EA-03-009 establishing interim inspection requirements for reactor pressure vessel heads at pressurized water reactors, February 11, 2003.

NRC Bulletin 2002-02, "Reactor Pressure Vessel Head and Vessel Head Penetration Nozzle Inspection Programs," August 9, 2002.

NRC Bulletin 2002-01, "Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity," March 18, 2002.

Information Notice 2002-11, "Recent Experience With Degradation of Reactor Pressure Vessel Head,"

March 12, 2002.

NRC Bulletin 2001-01, "Circumferential Cracking of Reactor Pressure Vessel Head Penetration Nozzles,"

August 3, 2001.

Information Notice 2001-05, "Through-Wall Circumferential Cracking of Reactor Pressure Vessel Head Control Rod Drive Mechanism Penetration Nozzles at Oconee Nuclear Station, Unit 3," April 30, 2001.

Generic Letter 97-01, "Degradation of Control Rod Drive Mechanism Nozzle and Other Vessel Closure Head Penetrations," April 1, 1997.

Information Notice 96-11, "Ingress of Demineralizer Resins Increases Potential for Stress Cracking of Control Rod Drive Mechanism Penetrations," February 14, 1996.

NUREG/CR-6245, "Assessment of Pressurized Water Reactor Control Rod Drive Mechanism Nozzle Cracking," October 1994.

75

Letter from Russell, W. T., (USNRC) to Rasin, W., (Nuclear Management and Resources Council), dated November 19, 1993, "Safety Evaluation for Potential Reactor Vessel Head Adaptor Tube Cracking."

Information Notice 90-10, 'Primary Water Stress Cracking of INCONEL 600," February 23, 1990.

Generic Letter 88-05, 'Boric Acid of Carbon Steel Reactor Pressure Boundary Components in PWR Plants," March 17,1988.

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Table 1 LLTF Report Recommendations Included in SCC Action Plan High Priority NUMBER RECOMMENDATION 3.1.1(1) The NRC should assemble foreign and domestic information concerning Alloy 600 (and other nickel based alloys) nozzle cracking and boric acid from technical studies, previous related generic communications, industry guidance, and operational events. Following an analysis of nickel based alloy nozzle susceptibility to stress cracking (SCC), including other susceptible components, and boric acid of carbon steel, the NRC should propose a course of action and an implementation schedule to address the results.

3.2.2(1) The NRC should inspect the adequacy of PWR plant boric acid control programs, including their implementation effectiveness, to determine their acceptability for the identification of boric acid leakage, and their acceptability to ensure that adequate evaluations are performed for identified boric acid leaks.

3.3.2(1) The NRC should develop inspection guidance for the periodic inspection of PWR plant boric acid control programs.

3.3.4(3) The NRC should strengthen its inspection guidance or revise existing guidance, such as IP 71111.08, to ensure that VHP nozzles and the RPV head area are periodically reviewed by the NRC during licensee ISI activities.

Such NRC inspections could be accomplished by direct observation, remote video observation, or by the review of videotapes. General guidance pertaining to boric acid observations should be included in IP 7111.08 3.3.4(8) The NRC should encourage ASME Code requirement changes for bare metal inspections of nickel based alloy nozzles for which the code does not require the removal of insulation for inspections. The NRC should also encourage ASME Code requirement changes for the conduct of non-visual NDE inspections of VHP nozzles. Alternatively, the NRC should revise 10 CFR 50.55a to address these areas.

Medium Priority NUMBER RECOMMENDATION 3.1.4(1) The NRC should determine if it is appropriate to continue using the existing SCC models as predictors of VHP nozzle PWSCC susceptibility given the apparent large uncertainties associated with the models. The NRC should determine whether additional analysis and testing are needed to reduce uncertainties in these models relative to their continued application in regulatory decision making.

77

Low Priority NUMBER RECOMMENDATION 3.3.7(6) Determine whether ISI summary reports should be submitted to the NRC, and revise the ASME submission requirement and staff guidance regarding I _ _ _Idisposition of the reports, as appropriate.

78

PWR SUMP PERFORMANCE TAC Nos. MA6454, MA2452, MA4014, MA0704, M95473, Last Update: 01/13/04 MA6204, MA0698, MB4047, MB6411, MB3103, MB8052, Lead NRR Division: DSSA MB7776, MB9470, MB4864, MB9931, MC0307, MC1154, Supporting Divisions: DE, DRIP, MB5625, MB4865, MC072516, MB5221, MB5964, DLPM, and DET (RES)

MB6589, MB7228, MC1627, MB5334, MC2628, MB6946 GSI: 191 MB9549. MC4272 MILESTONES DATE (TIC)

PART I: BWR ECCS SUCTION STRAINER CLOGGING ISSUE

1. NRCB 96-03, "Potential Plugging of Emergency Core Cooling Suction l 10/01 (C)

Strainers by Debris in Boiling-Water Reactors" PART II: NPSH EVALUATIONS

1. GL 97-04, "Assurance of Sufficient Net Positive Suction Head for Emergency Core Cooling and Containment Heat Removal Pumps" o Complete review of licensee responses 03/00 (C) o Complete revision of RG 1.1/RG 1.82, R3 11/03 (C)

PART III: CONTAINMENT COATINGS

1. GL 98-04, "Potential for Degradation of the Emergency Core Cooling 07/00 (C)

System and the Containment Spray System after a Loss-of-coolant Accident Because of Construction and Protective Coating Deficiencies and Foreign Material in Containment"

2. NRC-sponsored research program on the potential for coatings to fail 03/01 (C) during an accident PART IV: GSI 191, "ASSESSMENT OF DEBRIS ACCUMULATION ON PRESSURIZED WATER REACTOR (PWR) SUMP PERFORMANCE"

1. NRC-sponsored research program on the potential for loss of ECCS NPSH during a LOCA due to clogging by debris o Preliminary (qualitative) risk assessment (NRR) 03/99 (C) o Complete collection of plant data to support research program 06/99 (C) o Integrate industry activities into this Action Plan 04/00 (C) o Complete research program on PWR sump blockage 09/01 (C) o Evaluate need for regulatory action based on research program 03/02 (C) results (NRR) 79

MILESTONES MIETOE DATE DAT (T/C)

,T,

2. Resolve ECCS suction clogging issue for PWRs (Regulation/Guidance Development and Issuance Stages of GSI process in MD 6.4))

o Brief NRR ET to obtain approval to prepare a generic letter (GL) 02/02 (C) o Public meeting with NEI, WOG, B&WOG, CEOG 03/02 (C) o ACRS Briefing on proposed draft GL 02/03 (C) o CRGR Briefing on proposed Bulletin 2003-01 04/03 (C) o Information Paper to Commission, Issue Bulletin 2003-01 06/03 (C) o NEI publish PWR Industry Evaluation Guidelines (Draft) 10/03 (C) o CRGR Briefing on proposed draft GL 02/04 (C) o Proposed draft GL issued for Public Comment 03/04 (C) o GL issuance 09/04 (C) o Issue Safety Evaluation on Methodology 12/04 (C) o NRC starts Reviews of GL Responses and Selective Audits 09/05 (T) o Licensees start modifications, if needed, using approved guidelines 04/06 (T) o NRC closes GSI-1 91 12/07 (T)

==

Description:==

This action plan was originally prepared to comprehensively address the adequacy of ECCS suction design, and to ensure adequate ECCS pump net positive suction head (NPSH) during a loss-of-coolant accident (LOCA). Specifically, the concern is whether debris could clog ECCS suction strainers or sump screens during an accident and prevent the ECCS from performing its safety function. The plan is risk informed.

This plan has four parts; the first three have been completed. First, for boiling-water reactors (BWRs), this issue has been addressed by licensee responses to NRCB 96-03. Second, the adequacy of licensee (both PWR and BWR) net positive suction head (NPSH) calculations was evaluated through NRR review of licensee responses to GL 97-04, "Assurance of Sufficient Net Positive Suction Head for Emergency Core Cooling and Containment Heat Removal Pumps," dated October 7, 1997. The third part of the plan assessed the adequacy of the implementation and maintenance of licensee coating programs through NRR review of licensee responses to GL 98-04, "Potential for Degradation of the Emergency Core Cooling System and the Containment Spray System after a Loss-of-coolant Accident Because of Construction and Protective Coating Deficiencies and Foreign Material in Containment," dated July 14, 1998.

The remaining part of the action plan is an evaluation of the potential for clogging of PWR ECCS recirculation sumps during a LOCA. RES completed its assessment of the potential for debris clogging to support the resolution of GSI-191, "Assessment of Debris Accumulation on PWR Sump Performance."

RES performed a parametric evaluation to demonstrate whether sump blockage is a plausible concern for operating PWRs. The results of the parametric evaluation form a credible technical basis for concluding that sump blockage is a potential generic concern for PWRs; however, the parametric evaluation was ill-suited for determining whether sump blockage will impede or prevent long-term recirculation at a specific plant. By memorandum dated September 28, 2001, RES transferred the lead for GSI-191 to NRR.

Historical

Background:

During licensing of most domestic power plants, consideration of the potential for loss of adequate NPSH due to blockage of the ECCS suction by debris generated during a LOCA was inadequately addressed by both the NRC and licensees. The staff first addressed ECCS clogging issues in detail during its review of Unresolved Safety Issue (USI) A-43, "Containment Emergency Sump Performance." The NRC staff's concerns related to the potential loss of post-LOCA recirculation capability 80

due to insulation debris were discussed in GL 85-22, "Potential for Loss of Post-LOCA Recirculation Capability due to Insulation Debris Blockage," dated December 3, 1985. This generic letter documented the NRC's resolution of USI A-43. The staff concluded at that time that no new requirements would be imposed on licensees; however, the staff did recommend that Regulatory Guide 1.82, Revision 1, "Water Sources for Long-Term Recirculation Cooling Following a Loss-of-Coolant Accident," be used as guidance for the conduct of 10 CFR 50.59 reviews dealing with change out and/or modification of thermal insulation installed on primary coolant system piping and components. NUREG-0897, Revision 1, "Containment Emergency Sump Performance" (October 1985), contained technical findings related to USI A-43, and was the principal reference for developing the revised regulatory guide.

Since the resolution of USI A-43, new information challenged the adequacy of the NRC's conclusion that no new requirements were needed to prevent clogging of ECCS strainers in BWRs. On July 28,1992, an event occurred at BarsebAck Unit 2, a Swedish BWR, which involved the plugging of two containment vessel spray system (CVSS) suction strainers. The strainers were plugged by mineral wool insulation that had been dislodged by steam from a pilot-operated relief valve that spuriously opened while the reactor was at 435 psig. Two of the three strainers on the suction side of the CVSS pumps that were in service became partially plugged with mineral wool. Following an indication of high differential pressure across both suction strainers, the operators shut down the CVSS pumps and backflushed the strainers. The Barseback event demonstrated that the potential exists for a pipe break to generate insulation debris and transport a sufficient amount of the debris to the suppression pool to clog the ECCS strainers.

Similarly, on January 16 and April 14, 1993, two events involving the clogging of ECCS strainers occurred at the Perry Nuclear Power Plant, a domestic BWR. In the first Perry event, the suction strainers for the residual heat removal pumps became clogged by debris in the suppression pool. The second Perry event involved the deposition of filter fibers on these strainers. The debris consisted of glass fibers from temporary drywell cooling unit filters that had been inadvertently dropped into the suppression pool, and corrosion products that had been filtered from the pool by the glass fibers which accumulated on the surfaces of the strainers. The Perry events demonstrated high strainer pressure drop caused by the filtering of suppression pool particulates (corrosion products or 'sludge") by fibrous materials adhering to the ECCS strainer surfaces. This sludge is typically present in varying quantities in BWRs, since it is generated during normal operation. The amount of sludge present in the pool depends on the frequency of pool cleaning/desludging conducted by the licensee. The effect of particulate filtering on head loss had been previously unrecognized and therefore its effect had not been considered.

On September 11, 1995, Limerick Unit 1 control room personnel observed alarms and other indications that one safety relief valve (SRV) was open. Prior to the opening of the SRV, the licensee had been running the "A" loop of suppression pool cooling to remove heat being released into the pool by leaking SRVs. Shortly after a manual scram, and with the SRV still open, the "B" loop of suppression pool cooling was started. The reactor operators continued their attempts to close the SRV and reduce the cooldown rate of the reactor vessel. Approximately 30 minutes later, operators observed fluctuating motor current and flow on the "A" loop of suppression pool cooling. Cavitation was believed to be the cause, and the loop was secured. After it was checked, the "A" pump was successfully restarted and no further problems were observed. After the cooldown following the event, the licensee sent a diver into the Unit 1 suppression pool to inspect the condition of the strainers and the general cleanliness of the pool. The diver found that both suction strainers in the "A" loop of suppression pool cooling were almost entirely covered with a thin "mat" of material, consisting mostly of fibers and sludge. The "B" loop suction strainers had a similar covering, but less of it. Analysis showed that the sludge primarily consisted of iron oxides and the fibers were polymeric in nature. The source of the fibers was not positively identified, but the licensee determined that the fibers did not originate within the suppression pool, and contained no trace of either fiberglass or asbestos. This event at Limerick demonstrated the importance of foreign material exclusion practices to 81

ensure adequate suppression pool and containment cleanliness. In addition, the event re-emphasized that materials other than fibrous insulation could clog strainers.

NRCB 96-03, "Potential Plugging of Emergency Core Cooling Suction Strainers by Debris in Boiling-Water Reactors," was issued on May 6, 1996, requesting BWR licensees to implement appropriate procedural measures and plant modifications to minimize the potential for clogging of ECCS suction strainers by debris generated during a LOCA. Regulatory Guide 1.82, Revision 2, (RG 1.82), "Water Sources for Long-Term Recirculation Cooling Following a Loss-of-Coolant Accident," was issued in May 1996 to provide non-prescriptive guidance on performing plant-specific analyses to evaluate the ability of the ECCS to provide long-term cooling consistent with the requirements of 10 CFR 50.46. On November 20,1996, the Boiling Water Reactor Owners Group (BWROG) submitted NEDO-32686, "Utility Resolution Guidance for ECCS Suction Strainer Blockage" (also known as the URG) to the staff for review. The URG gave BWR licensees detailed guidance for complying with the requested actions of NRCB 96-03. The staff approved the URG in a safety evaluation report (SER) dated August 20,1998. In response to NRCB 96-03, all affected BWR licensees have installed new large-capacity passive strainers.

RES conducted an evaluation of the potential for PWRs to lose NPSH due to clogging of ECCS sump screens by debris during an accident because of new information learned during the development and resolution of NRCB 96-03. As noted above, the effect of filtering of particulates on head loss across the sump screen had previously been unrecognized. In addition, it was also learned that more debris could be generated than was previously assumed, and that the debris would be significantly smaller than was previously expected. With more and finer debris, the potential for clogging of the ECCS sump screen becomes greater, leading to the need to evaluate the potential for clogging of PWR sumps. RES's evaluation included a risk assessment.

Events at a number of plants raised concerns regarding potential for coatings to form debris during an accident which could clog an ECCS suction. Several cases have occurred where qualified coatings have delaminated during normal operating conditions. Typically, the root cause has been attributed to inadequate surface preparation. This led the staff to raise questions regarding the adequacy of licensee coating programs. The staff issued GL 98-04 to obtain necessary information from licensees to evaluate how they implement and maintain their coating programs. In addition, RG 1.54 was revised to update guidance for the selection, qualification, application, and maintenance of protective coatings in nuclear power plants to be consistent with currently employed ASTM Standards. The endorsement of industry consensus standards is responsive to OMB Circular A-1 19 and the NRC's Strategic Plan. RES also conducted research aimed at providing sufficient technical information regarding the failure of coatings to allow the staff to evaluate the potential for clogging of ECCS suctions by coating debris (or for coatings to contribute to ECCS suction clogging). The program evaluated the failure modes of coatings, the likely causes, the characteristics (e.g., size, shape) of the debris, and the timing of when coatings would likely fail during an accident. This information was used to evaluate the ability of the coating debris to transport to the ECCS suction screens or strainers during an accident and the ultimate effect on head loss. The conclusions from the coatings portion of this action plan were used in both RES's assessment of PWR sump clogging and in the staff's confirmatory evaluation of BWR solutions to the strainer clogging issue.

82

The NRC has developed web pages to keep the public informed of regulatory and research activities related to PWR sump performance:

http://www.nrc.gov/reactors/operating/ops-experience/pwr-sump-performance.html These web pages provide links to information regarding NRC interactions with industry (industry submittals, meeting notices, presentation materials, and meeting summaries) and publically available regulatory and research documents. The NRC will continue to update these web pages as new information becomes available.

Proposed Actions: This action plan involves an evaluation of PWR sumps based on new information learned during the development of the staff's resolution of NRCB 96-03. RES conducted a program to evaluate PWR sump designs and their susceptibility to blockage by debris. Risk insights supported the conclusions drawn relative to the need for licensees to address the potential for ECCS suction clogging.

The research program needed plant data to bound the problem to be evaluated. The Nuclear Energy Institute (NEI) conducted a survey of PWR licensees and provided the information needed by RES. The staff is coordinating its work with industry to eliminate duplication of effort and to ensure effective utilization of resources. RES parametrically evaluated whether sump blockage is a plausible concern for operating PWRs. The results of the parametric evaluation form a credible technical basis for concluding that sump blockage is a potential generic concern for PWRs.

Originating Document: Not Applicable.

Regulatory Assessment: Title 10, Section 50.46 of the Code of Federal Regulations (10 CFR 50.46) requires that licensees design their ECCS systems to meet five criteria, one of which is to provide the capability for long-term cooling. Following a successful system initiation, the ECCS shall be able to provide cooling for a sufficient duration that the core temperature is maintained at an acceptably low value. In addition, the ECCS shall be able to continue decay heat removal for the extended period of time required by the long-lived radioactivity remaining in the core. The ECCS is designed to meet this criterion, assuming the worst single failure.

As noted above, RES's parametric evaluation demonstrated that sump blockage is a plausible concern for operating PWRs. The results of the parametric evaluation form a credible technical basis for concluding that sump blockage is a potential generic concern for PWRs; however, the parametric evaluation is ill-suited for making a determination that sump blockage will impede or prevent long-term recirculation at a specific plant.

The staff considers continued operation of PWRs during the implementation of this action plan to be acceptable because the probability of the most challenging initiating event (i.e., large break LOCA) is extremely low. More probable (although still low probability) LOCAs (small, intermediate) will generate smaller quantities of debris, require less ECCS flow, take more time to use up the water inventory in the refueling water storage tank (RWST), and in some cases may not require the use of recirculation from the ECCS sump because the flow through the break would be small enough that the operator will have sufficient time to safely shut the plant down. In addition, all PWRs have received approval by the staff for leak-before-break (LBB) credit on their largest RCS primary coolant piping. While LBB is not acceptable for demonstrating compliance with 10 CFR 50.46, it does demonstrate that LBB-qualified piping is of sufficient toughness that it will most likely leak (even under safe shutdown earthquake conditions) rather than rupture. This, in turn, would allow operators adequate opportunity to shut the plant down safely.

Additionally, the staff notes that there are sources of margin in PWR designs which may not be credited in the licensing basis for each plant. For instance, NPSH analyses for most PWRs do not credit containment overpressure (which would likely be present during a LOCA). Any containment pressure greater than 83

assumed in the NPSH analysis provides additional margin for ECCS operability during an accident.

Another example of margin would be that it has been shown, in many cases, that ECCS pumps would be able to continue operating for some period of time under cavitation conditions. Some licensees have vendor data demonstrating this. Design margins such as these examples may prevent complete loss of ECCS recirculation flow or increase the time available for operator action (e.g., refilling the RWST) prior to loss of flow. And finally, the staff believes that continued operation of PWRs is also acceptable because of PWR design features which may minimize potential blockage of the ECCS sumps during a LOCA. The RES study on sump blockage attempted to capture many of the PWR design features parametrically, however, it is not possible for a generic study of this nature to capture all the variations in plant-specific features that could affect the potential for ECCS sump blockage (piping layouts, compartments, insulation location within containment, etc.). Therefore, evaluation on a plant-specific basis is necessary to determine the potential for ECCS sump clogging in each plant.

As part of the GSI-1 91 study, RES's contractor, Los Alamos National Laboratory (LANL), performed a generic risk assessment to determine how much core damage frequency (CDF) is changed by the findings of the parametric analysis. Utilizing initiating event frequencies that consider LBB credit consistent with NUREG/CR-5750, LANL calculated an overall CDF of 3.3E-06 when debris clogging as a failure mechanism is not considered, and an overall CDF of 1.5E-04 when debris clogging is considered.

However, these CDFs were calculated without giving any credit for operator action, and without consideration whether the ECCS or containment spray pumps would be able to continue operating if the headloss across the sump screen exceeds the calculated licensing basis NPSH margin. The change in CDF is also dominated by the small and very small break LOCAs which are events where there are significant operator actions that can be taken to prevent core damage. The risk benefit of certain interim compensatory measures is demonstrated by the NRC-sponsored technical report LA-UR-02-7562, "The Impact of Recovery from Debris-Induced Loss of ECCS Recirculation on PWR Core Damage Frequency,"

dated February 2003. On this basis, the schedule for issuing generic communications and followon actions to address the PWR sump clogging issue is considered to be appropriate.

Current Status: The staff continues to hold regular public meetings with the PWR owners groups and NEI sump performance task force on the progress toward resolving GSI-191.

The PWR Industry is implementing a two-step program to assess the current conditions and evaluate sump recirculation performance. The first guidance document, NEI 02-01, 'Condition Assessment Guidelines:

Debris Sources inside Containment," was published in September 2002. Consistent with the risk significance of the PWR sump-clogging concern, the staff issued Bulletin 2003-01 on June 9, 2003, requesting information on compliance within 60 days or information on interim compensatory measures to reduce risk until an evaluation to determine compliance is completed. The staff has issued RAls for the bulletin as needed, and is in the process of reviewing licensee's responses and issuing closeout letters.

NEI submitted the second guidance document, "PWR Containment Sump Evaluation Methodology on May 28, 2004. This document recommends methodologies for evaluating a PWR's susceptibility to sump clogging based upon the information collected in accordance with NEI 02-01. A refinements table and the risk-informed section, Section 6.0, were provided to the staff on July 7, 2004, and July 13, 2004, respectively. The staff prepared a Safety Evaluation (SE) to provide licensees an NRC-approved methodology to complete the site-specific evaluations as required in Generic Letter 2004-02, "Potential Impact of Debris Blockage on Emergency Recirculation During Design Basis Accidents at Pressurized-Water Reactors", which was issued on September 13, 2004, following CRGR endorsement on August 10, 2004. The Generic Letter had previously been presented to the ACRS sub-committee on June 22-23, 84

2004, and to the ACRS full-committee on July 7-9, 2004. The staff presented the SE to the ACRS T-H Sub-committee on September 22, 2004, the ACRS Full-committee on October 7, 2004, the CRGR on October 12, 2004, and issued the SE on December 6, 2004. The staff intends to conduct a public meeting on the generic letter and the safety evaluation on January 27-28, 2005, and supported the NEI workshop on the Evaluation methodology held on December 2-3, 2004.

NRR Lead PMs: Michael Webb, LPD 4, 415-1347 (GL 2004-02)

Alan Wang, LPD 4, 415-1445 (Bulletin 2003-01)

Jon Hopkins, LPD 3, 415-3027 (Safety Evaluation)

NRR Lead Section Chief: David Solorio, SPLB, 415-0149 NRR Technical Contacts: Ralph Architzel, SPLB, 415-2804 Angie Lavretta, SPLB, 415-3285 Tom Hafera, SPLB, 415-4097 HanryWagage, SPLB, 415-1840 Joe Golla, SPLB, 415-1002 Shanglai Lu, SPLB, 415-2869 Leon Whitney, DSSA, 415-3081 (Bulletin 2003-01)

David Cullison, SPLB, 415-1212 (Generic Letter)

Mark Kowal, SPLB, 415-1663 (Risk-informed approach)

Paul Klein, EMCB, 415-4030 (Chemical Effects)

Martin Murphy, EMCB, 415-3138 (Coatings)

Steve Unikewicz Engineering, 415-3819 (Downstream Effects)

RES Technical

Contact:

B. P. Jain, ERAB, 415-6303

References:

Regulatory Guide 1.1, "Net Positive Suction Head for Emergency Core Cooling and Containment Heat Removal System Pumps" (Safety Guide 1), dated November 1970.

Regulatory Guide 1.54, "Quality Assurance Requirements for Protective Coatings Applied to Water-Cooled Nuclear Power Plants" (Draft DG-1076, Proposed Revision 1, published March 1999), dated June 1973.

NRC Bulletin 93-02, "Debris Plugging of Emergency Core Cooling Suction Strainers," dated May 11, 1993.

NRC Bulletin 93-02, Supplement 1, "Debris Plugging of Emergency Core Cooling Suction Strainers," dated February 18, 1994.

NUREG/CR-6224, "Parametric Study of the Potential for BWR ECCS Strainer Blockage Due to LOCA Generated Debris" dated October 1995.

NRC Bulletin 95-02, "Unexpected Clogging of Residual Heat Removal (RHR) Pump Strainer While Operating in Suppression Pool Cooling Mode," dated October 17, 1995.

NRC Bulletin 96-03, "Potential Plugging of Emergency Core Cooling Suction Strainers by Debris in Boiling-Water Reactors" dated May 6, 1996.

85

NRC Bulletin 2003-01, "Potential Impact of Debris Blockage on Emergency Sump Recirculation at Pressurized-Water Reactors" dated June 9, 2003.

Regulatory Guide 1.82, Revision 3, "Water Sources for Long-Term Recirculation Cooling Following a Loss-of-Coolant Accident," dated November 2003.

GL 97-04, "Assurance of Sufficient Net Positive Suction Head for Emergency Core Cooling and Containment Heat Removal Pumps," dated October 7, 1997.

GL 98-04, "Potential for Degradation of the Emergency Core Cooling System and the Containment Spray System after a Loss-of-coolant Accident Because of Construction and Protective Coating Deficiencies and Foreign Material in Containment," dated July 14,1998.

Memorandum from Richard J. Barrett to John N. Hannon, "Preliminary Risk Assessment of PWR Sump Screen Blockage Issue," dated March 26,1999.

Memorandum from K. Kavanagh to G. Holahan, "Report on Results of Staff Review of NRC Generic Letter 97-04, 'Assurance of Sufficient Net Positive Suction Head for Emergency Core Cooling and Containment Heat Removal Pumps,"' dated June 26, 2000.

Letter from Gary M. Holahan to James F. Klapproth, "NRC Staff Review of GE Licensing Topical Report NEDC-32721 P. 'Application Methodology for the General Electric Stacked Disk ECCS Suction Strainers,'

TAC Number M98500," dated June 21, 2001.

NUREG/CR-6762, "GSI-191: Parametric Evaluations for Pressurized Water Reactor Recirculation Sump Performance," dated August 2002.

Memorandum from Ashok C. Thadani to Samuel J. Collins, "RES Proposed Recommendation for Resolution of GSI-191, 'Assessment of Debris Accumulation on PWR Sump Performance,'" dated September 28, 2001 (Accession Number ML012750149).

Memorandum from Robert B. Elliott to Gary M. Holahan, "Completion of Staff Reviews of NRC Bulletin 96-03, "Potential Plugging of Emergency Core Cooling Suction Strainers by Debris in Boiling-water Reactors," and NRC Bulletin 95-02, "Unexpected Clogging of a Residual Heat Removal (RHR) Pump Strainer While Operating in Suppression Pool Cooling Mode'" dated October 18, 2001 (Accession Number ML012970261).

NEI 02-01, "Condition Assessment Guidelines: Debris Sources inside Containment," Revision 1 published in September 2002.

NEI PWR Containment Sump Evaluation Methodology, letter dated May 28, 2004.

Technical Letter Report LA-UR-02-7562, "The Impact of Recovery from Debris-Induced Loss of ECCS Recirculation on PWR Core Damage Frequency," dated February 2003.

NUREG/CR-6808, "Knowledge Base for the Effect of Debris on Pressurized Water Reactor ECCS Sump Performance" dated February 2003.

Letter from Mario V. Bonaca to Nils Diaz, "Draft Final Revision 3 to Regulatory Guide 1.82, "Water Sources for Long Term Recirculation Cooling Following a Loss of Coolant Accident"," dated September 30, 2003.

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Generic Letter 2004-02, Potential Impact of Debris Blockage on Emergency Recirculation During Design Basis Accidents at Pressurized Water Reactors, dated September 13, 2004.

GSI-191 Safety Evaluation, Revision 0, "Pressurized Water Reactor Containment Sump Evaluation Methodology." dated December 6, 2004.

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GENERIC SAFETY ISSUE (GSI) 189 - SUSCEPTIBILITY OF ICE CONDENSER AND MARK III CONTAINMENTS TO EARLY FAILURE FROM HYDROGEN COMBUSTION DURING A SEVERE ACCIDENT TAC No. MB7245 Last Update: 12/30/04 Lead NRR Division: DSSA Supporting Division: DLPM, DRIP Supporting Office: RES MILESTONES DATE (T/C)

1. Transfer GSI from RES to NRR. Issue Resolution Process letter from 12/2002 (C)

J. Zwolinski, NRR, to F. Eltawila, RES.

2. Issue Task Action Plan - First draft for issuing Order. 03/14/03 (C)

Final draft ready for issuing an Order. 04/30/03 (C)

New draft for Rulemaking. 06/30/03 (C)

3. Engage the affected stakeholders: BWROG Management Meeting, ICUG, 02/19/03 (C) and NEI.

4. Review RES and contractor Cost and Benefit Analyses, technical 02/28/03 (C) assessment, and supporting/reference material. Conduct additional analyses if required.

5. Determine best solution and course of action (order, rule making, generic 02/12/03 (C) letter, severe accident management guidelines, etc.) Order initially selected.

6. Prepare regulation and guidance development memoranda and provide 03/05/03 (C) results and recommendations to NRR management. 03/05/03 (C)

7. Brief DLPM Management. 03/06/03 (C)

8. Brief LT and obtain approval for Order. 03/13/03 (C)

9. Distribute Draft Order and draft SECY Letter. 03/26/03 (C)

10. Provide Draft Order to OGC. 03/28/03 (C)

11. Brief ET. 03/19/03 (C)

12. Brief NRR/D. 03/19/03 (C)

13. Draft SECY Letter to EDO. 03/27/03 (C)

14. Finalize CRGR Package. 03/26/03 (C)

Course of action changed per OGC and ET - Will conduct a Public Meeting and pursue Rulemaking

15. Meet with Rulemaking Committee. 05/05/03 (C)

16. Schedule Public Meeting. 05/14/03 (C)

17. Issue Press Release regarding Public Meeting. 05/29/03 (C) 88

MILESTONES DATE (T/C)

18. Public Meeting. 06/18/03 (C)

19. Conduct Post Public Meeting Debrief and determine course of action. 06/18/03 (C)

20. Meet with OPA to develop Communications Plan and Website. 06/24/03 (C)

21. Complete Communications Plan Draft and route for approval. 07/10/03 (C)

22. Meeting with ACRS and Second Public Meeting to address issues 11/06/03 (C) regarding design criteria of backup power supply and cost/benefit analysis refinements.

23. Complete Stage 4, Regulation and Guidance Development of Management 01/31/04 (C)

Directive 6.4 and enter Stage 5, Regulation and Guidance Issuance.

24. Public Meetings with BWROG and NEI regarding hydrogen igniter back-up 02/03/04 (C) power supply design criteria. 03/31/04 (C)

25. Commissioner Merrifield brief. 03/04/04 (C)

26. SPLB staff briefed NRR associate director on the proposed rulemaking. 04/06/04 (C)

27. SPLB staff briefed DSSA director to propose other options, along with rule- 07/29/04 (C) making, for licensees to address the issue.

28. Draft design criteria issued to the NRR division directors for cognizant NRR 08/13/04 (C) staff's comment and approval.

29. Updating Communication Plan to be issued

30. Public meeting with external stakeholders to get stakeholders' comments on the draft design criteria and their input on voluntary initiatives for backup 09/21/04 (C) power supply to hydrogen igniters.

31. SPLB staff briefed DRIP/DSSA management to obtain management 11/15/04 (C) endorsement for actions to implement voluntary industry initiatives through issuance of a generic letter.

32. SPLB staff, with assistance from SPSB & RPRP, briefed the ET/LT on 11/29/04 (C) closure plans for GSI-189. A concensus was reached at the ET/LT meeting to go forward with letters (in lieu of a generic letter) to the owner's groups to capture voluntary licensees initiatives for providing backup power sources to hydrogen igniters.

33. The staff plans to issue letters to the owner's groups seeking commitment February 2005 for implementation of the proposed voluntary actions and include the design criteria as attachment to the letters

34. Evaluate voluntary actions to determine if plant specific backfits are Winter 2005 justified. _

35. Verify implementation through ROP engineering inspections. Winter 2005

==

Description:==

Following a severe accident concurrent with station blackout (SBO), the PWR ice condenser containment and BWR Mark IlIl containment are vulnerable to failures from hydrogen deflagrations and detonations. To resolve the generic safety issue, GSI-1 89, NRR recommended the addition of a backup power supply for the combustible gas igniters for the licensees with Ice Condenser or Mark IlIl 89

containments. The generic safety issue was proposed in response to SECY 00-198, 'Status Report on Study of Risk-Informed Changes to the Technical Requirements of 10 CFR Part 50 (Option 3) and Recommendations on Risk-informed Changes to 10 CFR 50.44 (Combustible Gas Control)." There are 13 susceptible plants involved. The affected plants are the four dual-unit PWR nuclear stations with ice condenser containments - McGuire, Catawba, DC Cook, and Sequoyah; a single-unit PWR nuclear station with ice condenser containment - Watts Bar; and four single-unit BWR nuclear plants with Mark IlIl containments - Grand Gulf, River Bend, Clinton, and Perry.

Historical

Background:

In response to SECY-00-198, the generic issue was proposed (Memorandum to John Flack, Chief, Regulatory Effectiveness and Human Factors Branch, Division of Systems Analysis and Regulatory Effectiveness, RES, from Mark Cunningham, Chief, Probabilistic Risk Analysis Branch, Division of Risk Analysis and Applications, RES, "Information Concerning Generic Issue on Combustible Gas Control for PWR Ice Condenser and BWR Mark III Containment Designs," August 15, 2001, ML012330522). This SECY paper explored means of making 10 CFR 50.44 risk-informed, and the paper recommended that safety enhancements that have the potential to pass the backf it test be assessed for mandatory application through the generic issue program.

Following a severe accident associated with a station blackout, the PWR ice condenser and BWR Mark IlIl containments are vulnerable to failures from hydrogen deflagrations or detonations, because the existing hydrogen igniters which are used to prevent hydrogen accumulation in large quantities cannot be energized due to lack of onsite and offsite AC power under SBO conditions.

At the request of the Office of Nuclear Regulatory Research (RES), a technical assessment was conducted by (1) Brookhaven National Laboratory (BNL) to perform the benefits analysis; (2) Information Systems Laboratories (ISL) to perform the cost analysis; and, (3) Sandia National Laboratories (SNL) to perform targeted plant analysis. RES staff also worked with the cognizant NRR staff throughout the development of this technical assessment.

For these analyses, initiating events, core damage frequencies (CDF), conditional containment failure (CCF) probabilities, and release categories were extracted from existing studies. The severe accident progression scenarios, including conditional containment failure probabilities, were based primarily on NUREG-1 150, "Severe Accident Risk: An Assessment of Five US Nuclear Plants." The conditional probability of early failure (CPEF) of containment was taken from NUREG/CR-6427, "Assessment of the DCH [direct containment heating] Issue for Plants with Ice Condenser Containments." Some plant specific analysis data was also used from Duke Power PRAs and the Sequoyah (ice condenser) and Grand Gulf (Mark l1l) plants. The combination of these data was then used to develop a cost-benefit analysis enveloping all the susceptible plants.

The technical assessment quantified the reduction in the conditional containment failure probability associated with combustible gas control being available during SBO events, which was then converted to a dollar value based on the expected values for averting public exposure and offsite property damage associated with the availability of combustible gas control. These averted costs (benefits) were then compared to the overall cost for the implementation and maintenance of several alternative safety enhancements to determine if there was a potential cost beneficial back-fit.

The RES analyses were based on consideration of internal events only. However, sufficient information was provided in the RES analyses associated with external events for some of the plants to evaluate the 90

impact external events could have on the analyses. When considering external events, averted costs increase substantially. Though the backup power system would not be required to be designed to withstand the external events that could be precursors of the SBO, it is expected that the small, backup power supply will be located in an area capable of withstanding those external events.

For PWRs with large dry or sub-atmospheric containments, containment loads associated with hydrogen combustion are non-threatening. However, it was discovered in the study associated with NUREG/CR-6427, "Assessment of the DCH (direct containment heating) Issue for Plants with Ice Condenser Containments," that the early containment failure probability is dominated by non-DCH hydrogen combustion events for ice condenser containments due to the relatively low containment free volume and low containment structural strength in these designs. These containments rely on the pressure-suppression capability of their ice beds. Therefore, for a design-basis accident, where the pressure is a result of the release of steam from blowdown of the primary (or secondary) system, an ability to withstand high internal pressures is not needed.

In a beyond-design-basis accident condition, where the core is severely damaged, significant quantities of hydrogen gas can be released. To deal with large quantities of hydrogen, the ice condenser containments are equipped with AC-powered igniters, which are intended to control hydrogen concentrations in the containment atmosphere by initiating limited "burns" before a large quantity accumulates. In essence, the igniters prevent the hydrogen (or any other combustible gas) from accumulating in large quantities and then suddenly burning (or detonating), posing a threat to containment integrity.

For most accident sequences, the hydrogen igniters can deal with the potential threat from combustible gas buildup. In the beyond-design-accident analysis, station blackout was postulated concurrent with a severe accident that would cause significant releases of radioactive material to the environment. The situation of interest for this generic safety issue only occurs during severe accident sequences associated with station blackouts, where the igniter system is not available because they are AC-powered.

The issue also applies to BWR Mark IlIl containments because they also have a relatively low free volume and low strength (comparable to those of the PWR ice condenser designs) and are potentially vulnerable in an severe accident sequence associated with station blackout. Consequently, the Mark IlIl designs also provide hydrogen igniters. The Mark I and Mark II designs are also pressure-suppression designs, but are operated with the containment "inerted," i.e., the drywell and the air space above the suppression pool are flooded with nitrogen gas arid a nitrogen makeup system maintains oxygen level below a set limit by maintaining a slight positive nitrogen pressure within the primary containment.

RES briefed the ACRS for the GSI-189 technical assessment on June 6, 2002, and November 7, 2002, and briefed the ACRS Thermal Hydraulic Phenomena and the Reliability and PRA Sub-committees on November 5, 2002. In a letter to the Commission dated November 13, 2002, the ACRS stated that they agreed with RES that further regulatory action by NRR was warranted for the plants with ice condenser and Mark III containments. RES also considered qualitative benefits, such as defense-in-depth, public confidence, and regulatory coherence, in their recommendation to pursue further action to provide backup power to one train of igniters for both ice condenser and Mark IlIl plants. Additionally, RES pointed out that the cost benefit analysis did not consider potential benefits due to averting some late containment failures.

The ACRS suggested that the form of action be through the use of plant-specific severe accident management guidelines (SAMG). In response to the ACRS letter, a letter from the EDO stated that the NRR staff would engage the affected stakeholders in developing additional information related to implementing various alternatives, including an option of using the SAMG. A public meeting was held on June 18, 2003, to discuss and receive comments on GSI-189. The licensees stated in the meeting that 91

they did not think that the use of SAMGs was viable because they are not implemented until late in the accident sequence and the igniters might be needed sooner. Also they felt that operator action to install a portable generator was not practical since it could distract operators from more critical activities associated with mitigating the accident. Therefore, NRR was basing its evaluation on a pre-staged system with procedures incorporated into emergency operating procedures (EOPs). This did not change the conclusion that the backfit should be pursued.

NRR staff's recommendations were presented to the ACRS on November 6, 2003, citing the results from recent studies which identified a near certainty of containment failure without the use of igniters during this severe accident. The ACRS recommended that NRR pursue upgrading the igniters through rulemaking, as well as providing guidance via SAMGs or EOPs. NRR recommended that backup power be provided to one train of the hydrogen igniter system, and met with the Boiling Water Reactor Owners' Group (BWROG) prior to making a decision to pursue rulemaking. NRR staff also discussed alternatives with the BWROG for the four affected BWR plants.

Proposed Actions: To resolve GSI-189, DSSA/SPLB developed a draft of the proposed design criteria for the backup power supply, and discussed it with the industry in the public meetings on February 3, and March 31, 2004. The draft design criteria incorporated the comments received from the industry, and was issued to the division directors of NRR for comment on August 13, 2004. SPLB also proposed other options that could be explored, as alternatives to rulemaking, for the affected licensees to address the issue since the staff believes that the NRC does not have a strong basis for pursuing rulemaking. This is because (1) GSI-1 89 is not a compliance issue, but a safety enhancement with no immediate safety concern and very low probability of occurrence, (2) safety enhancements require a substantial improvement in safety at justifiable cost, and (3) it is difficult to quantify the safety benefit of enhancement that only improve consequence mitigation capability. Adding backup power to the igniters improve defense-in-depth, but would not be easily defensible through the rulemaking process. Therefore, NRR is pursuing voluntary licensee initiatives as an alternative to rulemaking. In addition, DRIP/RPRP is completing the regulatory analysis to determine whether the cost for implementation is justifiable for the safety enhancement.

Originating Documents: Memorandum to John Flack, Chief, Regulatory Effectiveness and Human Factors Branch, Division of Systems Analysis and Regulatory Effectiveness, RES, from Mark Cunningham, Chief, Probabilistic Risk Analysis Branch, Division of Risk Analysis and Applications, RES, "Information Concerning Generic Issue on Combustible Gas Control for PWR Ice Condenser and BWR Mark IlIl Containment Designs," August 15, 2001, (ADAMS #IML012330522).

SECY 00-198, "Status Report on Study of Risk-informed Changes to the Technical Requirements of 10 CFR Part 50 (Option 3) and Recommendations on Risk-Informed Changes to 10 CFR 50.44 (Combustible Gas Control)."

Regulatory Assessment: Defense-in-Depth - as pointed out in the analyses, NRR technical staff recognized that there are significant uncertainties in both the cost and benefit calculations done by the RES which can shift the benefit to cost from a net negative number to a net positive number. NRR technical staff agreed with the RES and ACRS that the defense-in-depth philosophy is applicable for the reason to manage uncertainties, but the cost-benefit assessment needs to be completed through regulatory analysis based on the current design criteria.

92

Backfit Rule - NRR technical staff believes that adding backup power provides a safety enhancement that yields an increase in the overall protection of the public health and safety. The increase in safety may only be substantial at certain facilities within the affected population. NRR is performing additional analyses to determine whether the implementation costs are justified in view of this increased protection.

Current Status: The NRR staff is currently pursuing voluntary license initiatives instead of rulemaking. The NRR held a public meeting with the public and industry on September 21, 2004, to get stakeholders' input on the design criteria. Representatives of the PWR ice condenser utilities, the BWROG of the BWR Mark III utilities, and the Nuclear Energy Institute (NEI) discussed the proposed design criteria.

The representatives of PWR ice condenser containment utilities considered that the draft design criteria are generally acceptable. At the public meeting, Duke power, representing two PWR ice condenser sites, Catawba-1 &2, McGuire-1 &2, indicated a willingness to modify an existing safe-shutdown diesel generator that can manually hookup to the hydrogen igniters as needed. The American Electric Power (AEP) representative indicated a willingness to provide back up power for D.C. Cook 1&2 from new, large diesel generators which are already planned for installation to support an increased allowed outage time. The Tennessee Valley Authority (TVA), representing two PWR ice condenser containment sites, Sequoyah

-1&2, Watts Bar-1, indicated willingness to provide new design for the backup power supply as the standard emergency power on the 69Kv board. These utilities will provide their proposal to NRC for staff review in the near future. Currently, NRR has generally completed the design criteria with no major changes, and the contractor, ICF, completed the draft regulatory analysis in December 2004 and sent it to NRR for staff's comment.

However, the BWR licensees, BWROG representatives, stated that the 1-hour time limit is insufficient for the BWR Mark Ill containment to connect the backup power source to the hydrogen igniters without making the system automatic. The BWROG indicated a willingness to make hardware modifications to supply backup power from the existing high-pressure core spray (HPCS, division 3) diesel system, and agreed to provide additional information regarding implementation costs and the relative risk contribution from fast-SBO and slow-SBO at each of the Mark IlIl plants. The BWROG requested that NRC provide feedback whether the 2-hour power supply solution is viable.

Based on stakeholders' responses, a staff meeting was held on October 26, 2004, to discuss issues regarding (1) rulemaking versus other options to resolve GSI-1 89 and (2) 1-hour versus 2-hour time limits for the BWRs to connect the backup power source to hydrogen igniters. At the meeting, the staff agreed to proceed with voluntary industry initiatives through the issuance of a generic letter instead of rulemaking, and leave the design criteria unchanged. The SPLB staff briefed DRIP/DSSA divisional management on GSI-189 status in a meeting dated November 15, 2004, to obtain management endorsement of actions to implement voluntary industrial initiatives by issuing a generic letter and proposed to notify the Commission of the change from rulemaking. The SPLB staff, with assistance from the SPSB and RPRP, briefed the ET/LT in a meeting on November 29, 2004, on plans to resolve GSI-189. A consensus was reached at the meeting to go forward with letters (in lieu of a generic letter) to the owner's groups to capture voluntary licensee initiatives on providing backup power sources to hydrogen igniters. Additional milestones to implement this approach have been developed.

Contacts:

NRR Lead PM: L. Mark Padovan, DLPM/LPD 3-1, 415-1423 NRR Lead Technical Reviewer: Jin-Sien Guo, DSSA/SPLB, 415-1816 NRR Technical Reviewer: Ruth C. Reyes-Maldonado, DSSA/SPLB, 415-3249 NRR Technical

Contact:

Bob Palla, DSSAJSPSB, 415-1095 RES Technical

Contact:

Allen Notafrancesco, DSARE/SMS, 415-6499 93

References:

1. SECY-00-01 98, "Status Report on Study of Risk-informed Changes to the Technical Requirements of 10 CFR Part 50.

2. NUREG/CR-4551, Vol. 3, Rev. 1, Part 1, "Evaluation of Severe Accident Risks: Surry Unit 1, Main Report," October 1990.

3. NUREG/CR-4551, Vol. 3, Rev. 1, Part 3, "Evaluation of Severe Accident Risks: Surry Unit 1, External Events," December 1990.

4. NUREG/CR-4551, Vol. 5, Rev. 1, Part 1, "Evaluation of Severe Accident Risks: Sequoyah, Unit 1, Main Report," December 1990.

5. NUREG/CR-4551, Vol. 6, Rev. 1, Part 1, "Evaluation of Severe Accident Risks: Grand Gulf, Unit 1, Main Report," December 1990.

6. NUREG-l150, "Severe Accident Risks: An Assessment for Five U.S. Nuclear Power Plants,"

December 1990.

7. Letter from V. Mubayi, Brookhaven National Laboratory, to H. VanderMolen, NRC, 'NUREG-1 150 Consequence Calculations," July 20, 1994.

8. T. D. Brown et. al., "NUREG-1 150 Data Base Assessment Program: A Description of the Computational Risk Integration and Conditional Evaluation Tool (CRIC-ET) Software and the NUREG-1150 Data Base," letter report, March 1995.

9. NUREG/BR-01 84, "Regulatory Analysis Technical Evaluation Handbook," Final Report, January 1997.

10. 10 CFR 50.44, "Standards for combustible gas control system in light-water-cooled power reactors,"

January 1, 2000 (last revised 1987).

11. NUREG/CR-6427, "Assessment of the DCH Issue for Plants with Ice Condenser Containments," April 2000.

12. NUREG/BR-0058, "Regulatory Analysis Guidelines of the U.S. Nuclear Regulatory Commission," July 2000.

13. Memorandum to Samuel Collins, Director, Office of NRR, from Ashok Thadani, Director, Office of RES, September 29, 2000, regarding Research Information Letter RIL-0005, "Completion of Research to Address Direct Containment Heating Issue for All Pressurized Water Reactors." (ML003755724).

14. Memorandum to Ashok Thadani, Director, Office of RES, to Samuel Collins, Director, Office of NRR, November 22, 2000, regarding Research Information Letter RIL-0005, "Completion of Research to Address Direct Containment Heating Issue for All Pressurized Water Reactors." ML0037611979).

15. NUREG-1742, "Perspectives Gained from the Individual Plant Examination of External Events (IPEEE)

Program, Main Report," Draft Report for Public Comment, April 2001.

16. Memorandum to John Flack, Chief, Regulatory Effectiveness and Human Factors Branch, Division of Systems Analysis and Regulatory Effectiveness, RES, from Mark Cunningham, Chief, Probabilistic Risk Analysis Branch, Division of Risk Analysis and Applications, RES, "Information Concerning Generic Issue on Combustible Gas Control for PWR Ice Condenser and BWR Mark IlIl Containment Designs," August 15, 2001 (ML012330522).

17. Memorandum to M. Snodderly (NRC) from M. Zavisca and M. Khatib-Rahbar (ERI), "Combustible Gas Control Risk Calculations (DRAFT) for Risk-informed Alternative to Combustible Gas Control Rule for PWR Ice Condenser, BWR Mark I, and BWR Mark III (10 CFR 50.44)," October 22, 2001.

18. Management Directive 6.4 (MD 6.4), "Generic Issues Program," December 4, 2001.

19. Management Directive 6.3 (MD 6.3), "The Rulemaking Process," July 31, 2001.

20. Memorandum from John H. Flack, Chief, REAHFB:DSARE:RES to Jack E. Rosenthal, Chief, SMSAB:DSARE:RES and Mark A. Cunningham, Chief, PRAB:DRAA:RES, dated February 6, 2002, regarding "Panel Review of GSI-189, Susceptibility of Ice Condenser and Mark IlIl Containments to Early Failure from Hydrogen Combustion During a Severe Accident."

94

21. Memo from Farouk Eltawila, Director, RES, to Ashok C. Thadani, Director RES, dated February 13, 2002, regarding RES Task Action Plan for Resolving Generic Safety Issue 189: "Post Accident Combustible Gas Control in Pressure Suppression Containments."

22. Memorandum from William Travers, EDO, to The Commissioners, dated May 13, 2002 (SECY-02-0080), Proposed Rulemaking-Risk Informed 10CFR50.44, "Combustible Gas Control In Containment", (WITS 20010003).

23. Advisory Committee on Reactor Safeguards Meeting Minutes, 493w Meeting, June 6, 2002, regarding Technical Assessment Generic Safety Issue (GSI)-189.

24. Backup Power for PWRs with Ice Condenser Containments and for BWRs with Mark IlIl Containments under SBO Conditions: Impact Assessment, Rev. 2, September 24, 2002, by Information Systems Laboratories, Inc., Rockville, MD.

25. Hydrogen Control Calculations for the Sequoyah Plant, draft letter report, Rev. 3, September 30, 2002, by Sandia National Laboratories.

26. Memorandum from Ashok Thadani, RES to William Travers, EDO, dated October 1, 2002, regarding, "Revision to NRC's Regulatory Analysis Guidelines [NUREG/BR-0058] and RES Office Letter 1 to Conform to OMB's Information Quality Guidelines."

27. Benefit Cost Analysis of Enhancing Combustible Gas Control Availability at Ice condenser and Mark IlIl Containment Plants, draft letter report, October 4, 2002, by Brookhaven National Laboratory. ADAMS ML022880554.

28. Advisory Committee on Reactor Safeguards Subcommittee on Thermal-Hydraulic Phenomena and Subcommittee on Reliability and Probabilistic Risk Assessment Meeting Minutes, November 5, 2002, regarding Generic Safety Issue (GSI)-189.

29. Advisory Committee on Reactor Safeguards Meeting Minutes, 497h Meeting, November 7, 2002, regarding Technical Assessment Generic Safety Issue (GSI) -189.

30. Memo from George E. Apostolakis, Chairman Advisory Committee on Reactor Safeguards, to the Commission Chairman Richard A. Meserve, dated November 13, 2002, regarding "Recommendations Proposed by the Office of NAR for Resolving Generic Safety Issue -189, Susceptibility of Ice Condenser and Mark III Containments to Early Failure from Hydrogen Combustion During a Severe Accident. ML023230513

31. Memo from Ashok C. Thadani, Director RES, to Samuel J. Collins, Director, Office of Nuclear Reactor Regulation, dated December 17, 2002, regarding RES Proposed Recommendation for Resolving Generic Safety Issue 189: "Susceptibility of Ice Condenser and Mark IlIl Containments to Early Failure from Hydrogen Combustion During a Severe Accident." ML023510161

32. Attachment to Memo from Ashok C. Thadani, Director RES, to Samuel J. Collins, Director, Office of Nuclear Reactor Regulation, dated December 17, 2002, "Technical Assessment Summary for GSI-189: Susceptibility of Ice Condenser and Mark III Containments to Early Failure from Hydrogen Combustion During a Severe Accident."

33. Memo from John A. Zwolinski, Director, Division of Licensing Project Management, NRR to Farouk Eltawila, Director, Division of Systems Analysis and Regulatory Effectiveness, RES, dated January 21, 2003, regarding, "Resolution Process for Generic Safety Issue (GSI) 189, 'Susceptibility of Ice Condenser and Mark IlIl Containments to Early Failure from Hydrogen Combustion During a Severe Accident."

34. Memo from Jack Rosenthal, Branch Chief, Safety Margins and Systems Analysis Branch, Division of Systems Analysis and Regulatory Effectiveness, Office of Nuclear Regulatory Research to John Hannon, Branch Chief, Plant Systems Branch, Division of Systems Safety and Analysis, Office of Nuclear Reactor Regulation dated June 19, 2003, regarding, Final Contractor's Reports: Generic Safety Issue 189: "Susceptibility of Ice Condenser and Mark III Containments to Early Failure from Hydrogen Combustion During a Severe Accident."

95

35. Benefit Cost Analysis of Enhancing Combustible Gas Control Availability at Ice Condenser and Mark IlIl Containment Plants, Final Letter Report, Energy Sciences and Technology Department, Brookhaven National Laboratory, December 23, 2002 (ML031700011).

36. Backup Power for PWRs with Ice Condenser Containments and for BWRs with Mark IlIl Containments under SBO Conditions: Impact Assessment, Revision 2, Information Systems Laboratories, Inc.,

September 24, 2002 (ML031700015).

37. Hydrogen Control Calculations for the Sequoyah Plant, Final Letter Report, March 2003, Prepared By Sandia National Laboratories, March 2003 (ML031700025).

96

CONTROL ROOM HABITABILITY (INITIAL UPDATE)

TAC No. MC0021 Last Update: Initial Update Lead NRR Division: DSSA Supporting Division: TBD CTL: N/ A GSI No.: N/ A MILESTONE DATE (T/C)

Staff review of NEI 99-03 and redline and strikeout version provided to 04/17/01 (C)

NEI Control Room Habitability task force Staff will prepare Generic Letter and develop draft Regulatory Guides 07/01/01 (C) on Control Room Habitability at Nuclear Power Reactors (DG-1 114),

Demonstrating Control Room Envelope Integrity at Nuclear Power Reactors (DG-1115), Methods and Assumptions for Evaluating Radiological Consequences of Design Basis Accidents at Light Water Nuclear Power Reactors (DG-1 113), and Atmospheric Relative Concentrations for Control Room Radiological Habitability Assessments at Nuclear Power Plants (DG-1 111)

Office review of draft Regulatory Guides DG-1111 and DG-1113 12 /31/01 (C)

Office review of draft Regulatory Guides DG-1 114 and DG-1 115 and 03/01/02 (C) draft Generic Letter Brief CRGR on draft Regulatory Guides DG-1111 and DG-1113 12/31/01 (C)

Brief CRGR on draft Regulatory Guides DG-1114 and DG-1115 and GENERIC LETTER:

draft Generic Letter draft 04/29/02 (C)

DG-1114, DG-1115:

03/11/02 (C)

Issue draft Regulatory Guides DG-1111, DG-1113, DG-1114, and GENERIC LETTER:

DG-1 115 and draft Generic Letter for public comment draft 05/09/02 (C)

DG-1 111:

12/31/01 (C)

DG-1113:

01/31/02 (C)

DG-1114:

03/28/02 (C)

DG-1115:

03/28/02 (C)

Public meeting on draft Regulatory Guides DG-1111, DG-1113, RI: 07/11/02 (C)

DG-1114, and DG-1115 and draft Generic Letter RII: 07/16/02 (C)

RIII: 08/06/02 (C)

RIV: 07/18/02 (C) 97

Resolve public comments on draft Regulatory Guides DG-1 111, 12/30/04 DG-1113, DG-1114, and DG-1115 Office review and concurrence of final Regulatory Guides and Generic DG-1 111, DG-l 113:

Letter 01/31/03 (C)

DG1114, DG-1115, and GENERIC LETTER 2003-XX:

03/24/03 (C)

Brief ACRS on final Regulatory Guides and Generic Letter 04/10/03 (C)

Brief CRGR on final Regulatory Guides and Generic Letter 04/22/03 (C)

Commission Information Paper on Generic Letter 06/03 (C)

Issue final Regulatory Guides and Generic Letter 06/03 (C)

Review 60 days responses to Generic Letter 12/30/03 (C)

Develop replacement technical specification for Attachment B to 1/31/05-Regulatory Guide 1.196 Develop response to TSTF letter of 3/8/04 1/31/05 Transmit staff proposal for revision to TSTF-448 1/31/05 Review 180 days responses to Generic Letter 90 days after receipt Develop & transmit RAIs on 180 days responses to licensees 120 days after receipt of a) for responses received after 11/15/04 response (4/30/05) -

b) for licensees with complete responses submitted prior to 11/15/04 Conduct survey of 3-4 plants who filed 180 days responses to Generic 9/15/05 Letter Determine need for plant inspections 12/30/05 Develop Temporary Instruction 12/30/05 Conduct Plant Inspections TBD Assess overall response to Generic Letter TBD The date of 1/31/05 is just to develop a replacement technical specification. It is not a date when the revision would be issued to Regulatory Guide 1.196.

Beginning March 31,2005.

.7-8 prepared per month until back log is retired.

98

==

Description:==

In its review of license amendment submittals over the past several years, the staff has identified numerous problems associated with the assessment of control room habitability. These problems have included the overall integrity of the control room envelope and the manner in which licensees have demonstrated the ability of their control room designs to meet GDC-1 9. Licensees have failed to:

1. Assess the impact of proposed changes to plant design, operation, and performance on control room habitability,

2. Identify the limiting accident,

3. Appropriately credit the performance of control room isolation and emergency ventilation systems in a manner consistent with system design and operation, and

4. Substantiate assumptions regarding control room unfiltered inleakage.

In response to Item 4 above, several utilities performed testing of their control room envelope (CRE) to determine unfiltered inleakage using methods from ASTM E741-93, 'Standard Test Methods for Determining Air Change in a Single Zone by Means of a Tracer Gas Dilution." As of May 2003, about 30 percent of the operating plants' control rooms had been tested. At that time, all of the control rooms except one measured unfiltered inleakage which exceeded the design basis analysis assumptions. In several cases, the measured inleakage exceeded the design basis value by over an order of magnitude. In most of the cases to date, licensees have been able to ultimately demonstrate compliance to GDC-19 through corrective action and retesting or by re-analysis. The nearly 100 percent failure rate of such a large fraction of the operating plant control rooms created a large uncertainty in the ability of the remaining untested facilities to meet control room habitability requirements. These control room habitability issues adversely affected the timely review of many license amendment requests. Licensee and staff expended significant resources to resolve differences regarding licensing and design basis issues and weaknesses in analysis assumptions, inputs and methods. While the capability of untested control rooms to meet their design basis was in question, the staff has reasonable assurance that continued operation was safe since compensatory measures; e.g., use of self-contained breathing apparatus and potassium iodide were established by licensees.

Background:

General Design Criterion (GDC-19), "Control Room," of Appendix A, "General Design Criteria for Nuclear Power Plants," to 10 CFR Part 50, establishes criteria for a control room. It requires that a control room be provided which allows operators to take actions under normal conditions to operate the reactor safely and to maintain the reactor in a safe condition under accident conditions. GDC-1 9 also requires that equipment be provided at locations outside the control room with the design capability for hot shutdown of the reactor, including the necessary instrumentation and controls that both maintain the reactor in a safe condition during hot shutdown and possess the capability for the cold shutdown of the reactorthrough the use of suitable procedures. GDC-19 also requires that adequate radiation protection be provided to permit access and occupancy of the control room under accident conditions without personnel receiving radiation exposures more than 5 rem whole body, or its equivalent to any part of the body, for the duration of the accident. Applicants to build or license a new plant under Part 50 after January 10, 1997, applicants for design certification under Part 52 after January 10, 1997, applicants to build a new plant under Part 52 who don't reference a standard design certification, or current licensees who want to use an alternative source term as allowed by 50.67, are required by GDC-1 9 to use as the control room dose criterion 0.05 Sv (5 rem) total effective dose equivalent (TEDE). In March 1998, the staff briefed the Office of Nuclear Reactor Regulation Executive Team (ET) on its concerns related to the infiltration testing results and other aspects of control room habitability. The ET directed the staff to work 99

with the Nuclear Energy Institute (NEI) to resolve the issues. Pursuant to this direction, the staff co-hosted, with NEI and the Nuclear Heating Ventilation and Air Conditioning Users Group (NHUG), a workshop on control room habitability in July 1998. Following that workshop, NEI agreed to form a task force to address control room habitability. In August 1999, NEI submitted for staff review and comment a draft of a proposed NEI document intended to address this issue. This document, NEI 99-03, entitled, 'Control Room Habitability Assessment Guidance," did not adequately address the staff's concerns. In response to the staff concerns, NEI agreed in December 1999 to restructure NEI 99-03. During the period January through June 2000, the NEI task force met with the NRC staff in a series of public meetings to resolve outstanding issues and to discuss the content of NEI 99-03. A revision to NEI 99-03 revision was sent to the staff on October 13, 2000. The staff reviewed the October 13, 2000, revision and determined that, while there was much agreement on positions taken in the document, areas remained where the staff and industry were in disagreement. The staff determined, and NEI agreed, that the staff should reflect its position in formal regulatory guidance with outstanding issues resolved through the public comment process.

In June 2001 NEI issued Revision 0 of NEI 99-03, 'Control Room Habitability Assessment Guidance." This version was substantially the same as the October 13, 2000, draft reviewed by the NRC staff.

The NRC staff pursued a solution to the control room habitability issues with the NEI task force. The staff indicated its willingness to incorporate up-to-date information into its assessment of radiological analyses, consider possible changes in the radiological dose acceptance criteria and possible reductions in the conservatisms in control room habitability analyses.

NEI did not commit to making this industry initiative binding on individual utilities. The staff believed that a voluntary approach would not adequately resolve its concerns and that some generic approach would be needed. A Generic Letter would request licensees to take action to evaluate, in light of the ASTM E741 testing results to date, how licensees meet the requirements of GDC-19 with respect to unfiltered inleakage to their control room envelopes.

During staff interactions with the NEI issue task force, many issues were discussed. The staff believed that additional regulatory guidance was necessary in order that control room habitability issues were addressed in a complete and thorough manner. In addition, it was the staff's opinion that the regulatory information associated with control room habitability needed to be updated to reflect current knowledge. In meetings with the NEI Task Force on Control Room Habitability, changes to design basis accident radiological analysis assumptions were discussed. For those facilities whose licensing basis is based upon the TID-14844 source term, the staff and industry believed that it was necessary to consolidate existing information and to reflect current knowledge into one regulatory guide. For those licensees that implement an alternative source term as allowed by 10 CFR 50.67, Regulatory Guide 1.183, "Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors," provided guidance for performing control room radiological analyses. These regulatory guides provided the industry and public more realistic assumptions for performing radiological analyses.

The staff also believed that creating regulatory guidance on meteorology for control room habitability assessments was necessary and appropriate. It had been almost 20 years since the staff updated its information on control room habitability. Various staff and industry studies had been conducted in those 20 years. These studies had identified issues which were addressed to only a limited extent in the previous guidance on control room habitability. A regulatory guide on control room habitability would assist licensees in their determination of the present state of the integrity of their control room envelope. Along with the control room habitability regulatory guide, an additional regulatory guide on control room envelope integrity testing would provide guidance to the industry on how plants may determine control room envelope 100

integrity and continually demonstrate that integrity. Such regulatory guidance would utilize the information obtained from the testing that had already been conducted on 30 percent of the control room envelopes.

Therefore, control room habitability would be addressed through a Generic Letter and new Regulatory Guides on:

(1) Control room habitability, (2) Control room envelope integrity testing, (3) Meteorology for control room habitability assessments, and (4) Design basis accident radiological analyses.

Additionally, to support licensees that begin testing the integrity of the control room envelope by measuring unfiltered inleakage, the staff proposed to the Technical Specifications Task Force (TSTF) changes to standard technical specifications on control room emergency ventilation systems. The staff discussed these changes with the NEI control room habitability task force. The staff considered resolution of this issue supportive of the NRR pillars of maintaining safety, increasing public confidence (both by restoring control room integrity to the level assumed in the facility's licensing basis), increasing effectiveness and efficiency of key NRC processes (via a generic approach to resolution rather than the current plant-by-plant approach), and reducing unnecessary regulatory burden and increasing realism (due to possible relaxation in certain analysis assumptions and acceptance criteria, based on current information).

Four draft regulatory guides, numbered DG-1 111, DG-1 113, DG-1 114 and DG-1 115, were issued for public comment. Proposed Generic Letter 2002- XX, "Control Room Envelope Habitability," (ADAMS accession number ML021430317) was published on May 9, 2002, at 67 FR 31385. The staff completed review and disposition of comments received during the public comment period and completed making necessary revisions to the draft guides and generic letter. Regulatory Guide 1.194, Atmospheric Relative Concentrations for Control Room Radiological Habitability Assessments at Nuclear Power Plants, formerly DG-1 111 was issued in June 2003. Regulatory Guide 1.195, Methods and Assumptions for Evaluating Radiological Consequences of Design Basis Accidents at Light-Water Nuclear Power Reactors, formerly DG-1 113, Regulatory Guide 1.196, Control Room Habitability at Light-Water Nuclear Power Plants, formerly DG-1 114; and Regulatory Guide 1.197, Demonstrating Control Room Envelope Integrity at Nuclear Power Reactors, formerly DG-1 15, were issued in May 2003. Generic Letter 2003-01 was issued on June 12, 2003. The staff's proposed changes to technical specifications for control room emergency ventilation systems were included in Appendix B of Regulatory Guide 1.196.

During the finalization of the Regulatory Guides and the Generic Letter, NEI provided Revision 1 to NEI 99-03, "Control Room Habitability Assessment Guidance," March 11, 2003. The Generic Letter and Regulatory Guides referred to Revision 0 of NEI 99-03. Staff assessed the impact of Revision 1 and determined that revisions to the Generic Letter and Regulatory Guides were not necessary.

On December 30, 2002, NEI provided the Industry/ TSTF Standard Technical Specification Change Traveler TSTF-448, "Control Room Habitability," to the NRC for consideration. On July 1, 2003, the staff transmitted to NEI comments on Rev. 0 of TSTF-448. The staff held a meeting with the TSTF/NEI on July 11, 2003, to discuss its comments on Rev. 0. On August 19, 2003, Technical Specifications Task Force (TSTF) transmitted to the staff Rev. 1 to TSTF-448. On December 16, 2003, the staff provided comments and a request for additional information on Rev. 1. In a March 8, 2004, letter, the TSTF responded to the staff's comments. In that letter the TSTF also identified what they considered to be beneficial revisions to TSTF-448. The TSTF indicated that if the staff agreed with these proposed revisions a formal revision to TSTF-448 would be provided.

101

Proposed Actions: This proposed action plan provides for staff activities involving the assessment of licensee's verification and confirmation that their facility meets GDC 19. Licensee have and are responding to Generic Letter 2003-01. In their responses they have been requested to confirm their licensing basis including the inleakage characteristics of the CRE when their control room ventilation systems are functioning in response to a radiological or hazardous chemical challenge. In addition, licensees have been requested to confirm that a fire will not prevent the control room operators from controlling the reactor from either the control room or the alternate shutdown panel. Licensees have also been requested to address the adequacy of their technical specifications to demonstrate control room habitability. Licensees were also requested to address whether they currently utilize compensatory actions such as KI or self-contained breathing apparatus in order to meet GDC 19 and, if they do, when such compensatory actions will be retired. Licensees were asked to identify if they thought that their facility was licensed such that it was not required to meet GDC 19 or its equivalent as presented in the draft GDCs or in the draft Principle Design Criteria. The staff will review the licensee's response to the Generic Letter and, if necessary, develop requests for additional information as part of that assessment. In conjunction with the Davis Besse Lessons Learned, the staff will perform a survey of 3-4 plants to assess the manner in which licensees have responded to the Generic Letter. These surveys will be conducted at the plant sites. It is intended that the survey will give the staff a sense of licensee's verification and confirmation processes in developing their responses. It would provide the staff data on whether licensees have responded to the Generic Letter in the manner in which the staff expected. The survey would be utilized to establish the framework and the protocol for plant inspections and the TI should they be necessary. During the survey, the staff would be confirming the licensee's response. It is anticipated that these surveys will provide data as to whether plant inspections should be conducted. If it is determined that inspections are necessary, a temporary instruction will need to be developed. This TI will be utilized to conduct the inspections. The number of inspections to be conducted will be a function of the finding but it is anticipated that a minimum of 4-6 plants will be inspected. From these inspections, an overall assessment of licensee's responses to the Generic Letter may be made.

Originating Document: None.

Regulatory Assessment: The staff believes that the potential deficiencies in the control room habitability designs, operations, and analyses represent safety issues that warrant resolution. It is important to recognize that the objective of control room habitability requirements, such as those in GDC-19, is not to minimize operator exposure for the purposes of ALARA (which is controlled under 10 CFR Part 20), but to provide a habitable environment in which to take action to operate the reactor safely under normal conditions and to maintain it in a safe condition under accident conditions. The dose criterion of 5 rem whole body was selected as it was believed that operations personnel would not be distracted from necessary plant operations and would not unnecessarily evacuate the controls area due to concerns for their personal safety. Protection against smoke and other toxic gases is also necessary since these hazards could cause, in some cases, immediate physical impairment or incapacitation of control room operators. While toxic gases are considered in control room habitability analyses in accordance with the guidance in Regulatory Guide 1.78, the potentially toxic byproducts of fires and their impacts on control room habitability were not considered a problem in the past because of the presumed integrity of the control room envelope. In the past, a fire outside the control room was considered to have no impact upon the operators because smoke and toxic fire gases were never presumed to enter the control room envelope. If a fire occurred in the control room, the operators had the remote shutdown areas for controlling the reactor. Testing of the control room envelope's integrity has demonstrated that the perceived integrity does not exist. Consequently, some portions of the smoke issue may be covered under this action plan while other aspects may not. The staff considered the risk impacts of control room habitability and made a preliminary determination that control room habitability has not been addressed in current PRAs because:

102

(1) It has been assumed that the design basis was being met, and (2) Quantification of the risk associated with failure to meet the design basis for control room habitability is not addressed by current metrics, methods, and risk experience data.

Current Status: As of December 31, 2003, approximately 65 percent of the plants provided 60 days responses to the Generic Letter. The remainder provided a complete response. As of November 1, 2004, 60 percent of the plants have now provided completed responses. Approximately 7 percent of the reactors will be testing the integrity of their CRE in 2005. Approximately 5 percent of the reactors do not intend to test their CREs. Licensees that have performed integrated tracer gas leakage testing of their control room envelopes continue to inform the NRC staff of their findings in their response to the Generic Letter.

The staff has identified issues associated with the proposed technical specification in Appendix B of Regulatory Guide 1.196. The staff is proposing to revise these issues by issuing a revision to the Appendix.

The staff needs to review the complete responses to the Generic Letter to determine whether licensees have actually confirmed and verified their licensing basis, that they have adequately determined the inleakage characteristic of the CRE and that reactor control may be maintained from the control room or the alternate shutdown panel in the event of a fire, radiological or hazardous chemical challenge. The staff also must determine when those facilities which are currently using compensatory actions such as self-contained breathing apparatus or KI and when they intend to retire those actions.

Contacts:

NRR Lead PM: M. Webb, PD4-1/DLPM/NRR, 415-1347 NRR Technical Contacts: R. L. Dennig SPSB/DSSA/NRR, 415-1156 J. J. Hayes, SPSB/DSSA/NRR, 415-3167 W. M. Blumberg SPSB/DSSA/NRR, 415-1083 H. Walker SPSB/DSSA/NRR, 415-2827

References:

USNRC, Title 10 Code of Federal Regulations Part 50, Appendix A.

USNRC, "Clarification of TMI Action Plan Requirements," NUREG-0737, 1980.

USNRC, 'Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants,"

NUREG-0800.

L. Soffer, et al, "Accident Source terms for Light Water Nuclear Power Plants," NUREG-1465, 1995.

Murphy, K. G. and Campe, K. W., "Nuclear Power Plant Control Room Ventilation System Design for Meeting General Criterion 19, " published in proceedings of 13th AEC Air Cleaning Conference.

Driscoll, J. W., 'Control Room Habitability Survey of Licensed Commercial Nuclear Power Generating Stations," NUREG/ CONTROL ROOM-4960,1988.

DiNunno, et al, 'Calculation of Distance Factors for Power and Test Reactor Sites," Technical Information Document TID-1 4844, USAEC, 1962.

USNRC, Regulatory Guide 1.183, "Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors," 2000.

American Society for Testing and Materials ASTM E741, "Standard Test Methods for Determining Air Change in a Single Zone by Means of a Tracer Gas Dilution," 1993.

103

FIRE PROTECTION PROGRAM (INITIAL UPDATE)

TAC Nos. M40015, MA1139, MA1752, MA4507, MA4720, Last Update: Initial Update MA4721, MA9013, MA9014, MA9015, MA9016, MB1311, Lead NRR Division: DSSA MB1313, MB2921, MB3203, MB6729, MB6932, MB7726, Supporting Divisions: DIPM, MB8731, MC0514, MC0627, MC0628, MC0774, MC0843, DRIP, and DRAA (RES)

MC0844, MC0987, MC0988, MC1202, MC1203, MC1386, Supporting Offices: OE, OGC MC1 825, MC1 826, MC1 833, MC2099, MC21 00, MC2267, MC2364, MC2268, MC2582, MC2584, MC2589, MC3096, MC3097, MC3100, MC3184, MC3272, MC3273, MC3628, MC3743, MC3744, MC3778, MC3779, MC3796, MC3812, MC3865, MC4011, MC4310, MC4395, MC4639, MC4640, MC4645, MC4646, MC5150, MC5175 MILESTONES DATE (TC ITEM I: RISK-INFORMED PERFORMANCE-BASED RULE IMPLEMENTATION (NFPA 805)

1. Publish final rule 06/04 (C)

2. Complete review of NEI implementation guide (NEI 04-02, Rev. F) 07/04 (C)

3. Complete draft Regulatory Guide (RG) (DG-1 139) 08/04 (C)

4. Issue DG-1 139 for public comment 09/04 (C)

5. Public meeting on implementation, DG-1139, & inspection concepts 10/04 (C)

6. Comment on draft fire PRA requantification report (NUREG/CR-6850) 11/04 (C)

7. Receive DG-1 139 public comments 12/04 (C)

8. Commission decision on enforcement discretion extension 01/05 (T)

9. Develop inspection template task force guidance 01/05 (T)

10. Issue draft pilot plant observation guidance in public mtg notice 01/05 (T)

11. Form task force to develop draft inspection template 02/05 (T)

12. Public meeting on DG-1139, pilot plant reviews, NEI 04-02, NEI Pilots 02/05 (T)

13. RIC Fire Protection Session - Implementation Challenges 03/05 (T)

14. Complete incorporation of public comments into final regulatory guide 03/05 (T)

15. Obtain DSSA approval on final RG 04/05 (T)

16. Send final regulatory guide to ACRS, CRGR, & Regions for review 04/05 (T)

17. Task force workshops to develop draft inspection template 04/05 (T)

18. ACRS meeting on final regulatory guide 05/05 (T)

19. CRGR meeting on final regulatory guide 05/05 (T) 104

MILESTONES DATE (T/C)

20. Incorporate ACRS, CRGR, & Regional comments into final reg. guide 06/05 (T)

21. Complete HQ & Regional draft inspection template review 06/05 (T)

22. Obtain final approval on regulatory guide and send for publication 06/05 (T)

23. Publish final regulatory guide endorsing NEI 04-02, Rev. 0 07/05 (T)

24. Public Meeting discussing draft inspection template 07/05 (T)

25. Review final fire PRA requantification (NUREG/CR-6850) prior to entry 08/05 (T) into ADAMS

26. Anticipating first licensee letter of intent to transition 08/05 (T)

(Oconee Nuclear Station)

27. Issue final pilot plant observation guidance 09/05 (T)

28. Review final RES report on acceptable fire models 09/05 (T)

29. Incorporate inspection template into inspection procedure 12/05 (T)

ITEM II:POST-FIRE SAFE-SHUTDOWN CIRCUIT ANALYSIS RESOLUTION

1. Suspend selected circuit inspections 11/00 (C)

2. Perform and analyze circuits test data 01/01 (C)

3. Issue RIS 2004-03, Revision 0 on circuit analysis 03/04 (C)

4. Revise inspection procedures for Regions' review 06/04 (C)

5. Conduct NRC inspector training 07/04 (C)

6. Conduct public meeting to discuss NEI 00-01 07/04 (C)

7. Develop primarily circuit screening tool 08/04 (C)

8. Conduct public meeting in Atlanta 10/04 (C)

9. Conduct public meeting on NEI 00-01 comments 11/04 (C)

10. Issue revised inspection procedures 12/04 (C)

11. Issue revised MC 0305 Section 6 12/23 (C)

12. Resume circuit inspections 01/05 (T)

13. Issue RIS 2004-03, Revision 1 on circuit analysis 12/04 (C)

14. Conduct public meeting on RIS 2004-03 Rev 1 03/05 (T)

15. Form NRC support panel on circuit issues to address outstanding 03/05 (T) unresolved items (URI's) and inspection findings

16. Issue draft RIS to provide clarification of regulatory requirement issues 03/05 (T) associated with post-fire safe-shutdown circuit analysis and protection.

105

MILESTONES l DATE (T/C)

17. Receive and address comments on circuit issues/compliance l 05/05 (T)

18. Issue final RIS on circuit issues/compliance 09/05 (T)

ITEM Ill: OPERATOR MANUAL ACTIONS RULEMAKING

1. Prepare proposal for rulemaking plan 03/03 (C)

2. Commission approval of rulemaking plan 09/03 (C)

3. Publish interim criteria for enforcement discretion for public comment 11/03 (C)

4. Conduct public meeting for comments on draft interim criteria 11/03 (C)

5. ACRS fire protection Subcommittee briefing on technical basis for 04/04 (C) interim criteria

6. Conduct public meeting on requirement for detection/suppression 06/04 (C)

7. Submit draft interim criteria for enforcement discretion to Office of 07/04 (C)

Enforcement (OE) l

8. Re-issue modified interim criteria for enforcement discretion to OE 09/04 (C)

9. Brief the fire protection Subcommittee and the Full Committee of ACRS 10-11/04 (C)

10. Issue interim enforcement discretion (NRC decided to rely on current 12/04 (C) enforcement discretion on circuits for manual actions)

11. Submit proposed rule to Commission 12/04 (C)

12. Issue proposed rule for public comment with draft Regulatory Guide 02/05 (T)

(RG)

13. Publish final rule and RG 01/06 (T)

ITEM IV: EMERGING FIRE PROTECTION ISSUES RESOLUTION

1. Hemyc and M.T., fire barrier performance qualification o Review 1-hour Hemyc fire performance test report 06/05 (T) o Meet with industry/licensees, if required 06/05 (T) o Review 3-hour M.T., fire performance test report 09/05 (T) o Meet with industry/licensees, if required 09/05 (T)

2. Epoxy coatings o Review NEI white paper 01/05 (T) o Develop response and have NRC Regional Offices review 02/05 (T) o Issue response to NEI white paper 04/05 (T) oMeet with industry/licensees, if required 05/05 (T) 106

MILESTONES T DATE (T/C)

3. RCP sear performance inspection findings o Research inspection reports and Appendix R 07/04 (C) o Respond to Westinghouse Owners Group (WOG) letter 11/04 (C) o Issue Information Notice 01/05 (T) o Receive WOG input on seal performance 01/28 (T) o Review WOG input and resolve unresolved items (URls) 06/05 (T)

4. Manual lockout of automatic carbon dioxide fire suppression systems o Review NEI white paper 01/05 (T) o Develop response and have NRC Regional Offices review 03/05 (T) o Issue response to NEI white paper 04/05 (T) o Meet with industry/licensees, if required 05/05 (T) o Issue Generic Communication (if necessary) 06/05 (T)

ITEM V: REGULATORY TOOLS DEVELOPMENT

1. Quantitative Fire Hazard Analysis Tools - NUREG-1805 o Research and write text and spreadsheets 01/01 (C) o Publish draft NUREG-1805 06/03 (C) o Present NUREG-1805 at EPRI meeting in Maryland 09/03 (C) o Present NUREG-1805 at EPRI meeting in Florida 09/04 (C) o Publish softbound advanced copy of NUREG-1 805 11/04 (C) o Conduct public meeting on applications of NUREG-1 805 11/04 (C) o Publish hardbound NUREG-1805 with final spreadsheets 01/05 (T)

2. Fire PRA Requantification Report (NUREG/CR-6850) - by RES o Review draft of NUREG 10/04 (C) o Provide comments to RES 01/05 (T) o Review final NUREG prior to ACRS review 03/05 (T)

3. Fire Model Verification and Validation (V&V) Report - by RES o Provide guidance on the study's interrelation with NFPA 805 07/01 (C) o Review V&V draft documents 03/05 (T) o Review final V&V documents 06/05 (T) 107

I MILESTONES I DATE (T/C)

4. American Nuclear Society (ANS) Fire PRA Standard o Review draft standard by NRR member of review committee 12/04 (C) o Review final standard by NRR member of review committee 06/05 (T) o Review standard upon issuance to public 12/05 (T) o Endorse in RG 1.200 TBD

==

Description:==

Today the fire protection programs (FPPs) at U.S. nuclear power plants have the primary goals of minimizing both the probability of occurrence, and consequences of fire. To meet these goals, the FPPs for operating nuclear power plants are designed to provide reasonable assurance that a fire will not prevent the performance of necessary safe shutdown functions and will not significantly increase the risk of radioactive releases to the environment. The primary FPP objectives for operating reactors are to:

• Prevent fire from starting,

• Detect, rapidly control, and promptly extinguish those fires that do occur, and

• Protect structures, systems, and components important to safety so that a fire that is not promptly extinguished will not prevent the safe shutdown of the plant.

The FPP objectives at plants that have permanently ceased operations are to:

• Reasonably prevent fires from occurring,

• Rapidly detect, control and extinguish those fires that do occur that could result in a radiological hazard, and

• Ensure that the risk of fire-induced radiological hazards to the public, environment and plant personnel is minimized.

The challenges within the FPP stem from (1) the fact that we have prescriptive regulations that are subject to different interpretations and are not always able to be enforced in a clear and consistent way, and (2) the fact that licensees have varying degrees of specificity in their licensing basis and in some cases are substantially different, which can also lead to different interpretations of regulatory intent. The activities described below address these challenges with the objective of achieving the strategic plan.

ITEM I: RISK-INFORMED PERFORMANCE-BASED RULE IMPLEMENTATION (NFPA 805)

Historical

Background:

The goal of revising 10 CFR 50.48 is to allow licensees to adopt a risk-informed, performance-based approach to fire protection as described in the consensus standard NFPA 805,

'Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants." The revised rule provides a means to re-establish poorly defined fire protection licensing bases and enables licensees to manage their fire protection programs with minimal regulatory intervention. NEI developed NEI 04-02, "Guidance for Implementing a Risk-informed, Performance-Based Fire Protection Program under 10 CFR 50.48(C)." The staff endorsed this guidance in the draft regulatory guide DG-1 139, "Risk-Informed, Performance-Based Fire Protection for Existing Light-Water Nuclear Power Plants."

Proposed Actions: See Milestone chart.

108

Oriqinating Document: SECY Paper 00-0009, "Rulemaking Plan, Reactor Fire Protection Risk-Informed, Performance-Based Rulemaking", dated January 2000.

Regulatory Assessment: See Historical Background.

Current Status: The public comment period on the draft regulatory guide, DG-1 139, endorsing NEI 04-02, Rev. F has ended. The Staff is working to incorporate the comments in a final regulatory guide and NEI is revising NEI 04-02, Rev. F. The SPLB staff has worked with Office of Enforcement (OE) to develop a letter for the Executive Director of Operations (EDO) to send the Commission on extending the due date for enforcement discretion for existing non-compliances from January 15, 2005 to December 31, 2005. The staff is planning to pilot the first couple of transitioning licensees. PNNL has developed and the staff is reviewing the guidance for these pilots. Presentations are being prepared for the next public meeting to cover draft pilot plant observation guidance, and DG-1 139 and NEI 04-02 revisions. Presentations are also being developed for the Regulatory Information Conference. Guidance is being developed for a task force of Headquarters and Regional staff to develop an NFPA 805 inspection template.

NRR Lead Section Chief: Sunil Weerakkody, SPLB, 415-2870 NRR Technical Contacts: Paul Lain, SPLB, 415-2346 Robert Radlinski, SPLB, 415-3174 Rick Dipert, SPLB, 415-4064 RES Technical

Contact:

Mark Salley, PRAB/DRAA, 415-2840

References:

Draft Regulatory Guide DG-1 139, "Risk-informed, Performance-Based Fire Protection For Existing Light-Water Nuclear Power Plants", dated October 2004.

SECY Paper 00-0009, "Rulemaking Plan, Reactor Fire Protection Risk-Informed, Performance-Based Rulemaking", dated January 2000.

SECY Paper 02-132, "Proposed Rule: Revision of 10 CFR 50.48 to Permit Light-Water Reactors to Voluntarily Adopt National Fire Protection Association (NFPA) Standard 805, "Performance-Based Standard for Fire Protection for Light-Water Reactor Electric Generating Plants," 2001 Edition (NFPA 805) as an Alternative Set of Risk-informed, Performance-Based Fire Protection Requirements", dated July 2002.

NUREG/BR-0312, "The Alternate Fire Protection Regulation", dated September 2004.

NFPA 805, "Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants," 2001 Edition, National Fire Protection Association, Quincy, Massachusetts.

Staff Requirements Memorandum M040511A, "Affirmation of SECY-04-0050 - Final Rule: Revision of 10 CFR 50.48 to Allow Performance-based Approaches Using National Fire Protection Association (NFPA)

Standard 805, NPerformance-based Standard for Fire Protection for Light Water Reactor Electric Generating Plants," 2001 Edition", dated May 2004.

NEI 04-02, Rev. F, "Guidance for Implementing a Risk-informed, Performance-Based Fire Protection Program Under 10 CFR 50.48 (C)", dated July 2004.

109

ITEM II: POST-FIRE SAFE-SHUTDOWN CIRCUIT ANALYSIS RESOLUTION Historical

Background:

The goal of the Post-Fire Safe-Shutdown Circuit Analysis is to provide guidance to licensees and NRC inspectors on a risk-informed approach to inspection of post-fire safe-shutdown spurious actuations resulting from failure of circuits. The guidance documents, developed in cooperation with industry, will be used to bring clarity to a long-standing unresolved issue.

Proposed Actions: See Milestone chart.

Originating Document: Information Notice 99-17, "Problems Associated with Post-Fire Safe-Shutdown Circuit Analysis", dated June 1999.

Regulatory Assessment: See Historical Background.

Current Status: The revised inspection procedures have been drafted and issued. The NRC met with NEI on July 28th to discuss NEI 00-01, "Guidance for Post-Fire Safe-Shutdown Analysis," Rev. 0, and NEI 04-06, "Guidance for Self-Assessment of Circuit Failure Issues." The first round of NRC inspector workshops has been completed. Post-Fire Safe-Shutdown Circuit inspections will restart in January 2005.

The staff issued RIS 2004-03, Risk-Informed Approach for Post-Fire Safe-Shutdown Associated Circuit Inspections," originally on March 2, 2004, to both risk-inform circuit analysis and provide details on the enforcement discretion available On December 29, 2004, Revision 1 to the RIS was issued. A second RIS to clarify the expectations of compliance is being developed.

NRR Lead Section Chief: Sunil Weerakkody, SPLB, 415-2870 NRR Technical Contacts: Dan Frumkin, SPLB, 415-2280 Robert Radlinski, SPLB, 415-3174 Ray Gallucci, SPLB, 415-1255 RES Technical

Contact:

Mark Salley, PRAB/DRAA, 415-2840

References:

NRC Bulletin 75-04, "Cable Fire at Browns Ferry Nuclear Power Station", dated March 1975.

NRC Bulletin 92-01, "Failure of Thermo-Lag 330 Fire Barrier System to Maintain Cabling in Wide Cable Trays and Small Conduits Free From Fire Damage", dated June 1992.

Information Notice 84-09, 'Lessons Learned From NRC Inspections of Fire Protection Safe Shutdown Systems (10 CFR 50, Appendix R)", dated February 1984.

Information Notice 84-09r1, "Lessons Learned From NRC Inspections of Fire Protection Safe Shutdown Systems (10 CFR 50, Appendix R)", dated March 1984.

Information Notice 99-17, "Problems Associated with Post-Fire Safe-Shutdown Circuit Analysis", dated June 1999.

Regulatory Issue Summary 04-03, "Risk-informed Approach for Post-Fire Safe-Shutdown Associated Circuit Inspections", dated March 2004.

110

Regulatory Issue Summary 04-03, Rev. 1, "Risk-Informed Approach for Post-Fire Safe-Shutdown Circuit Inspections", dated December 2004.

"Circuit Analysis-Failure Mode and Likelihood Analysis," A Letter Report to USNRC, Sandia National Laboratory, Albuquerque, New Mexico, ADAMS Accession # ML010450362, dated May 8, 2000.

NUREG/CR-6776, -Cable Insulation Resistance Measurements Made During Cable Fire Tests," Office of Nuclear Regulatory Research, U.S. Nuclear Regulatory Commission, Washington, DC, dated June 2002.

NUREG/CR-6834, "Circuit Analysis - Failure Mode and Likelihood Analysis," Office of Nuclear Regulatory Research, U.S. Nuclear Regulatory Commission, Washington, DC, dated September 2003.

Draft NUREG-1 778, "Knowledge Base for Post-Fire Safe-Shutdown Analysis", dated January 2004.

NEI 00-01, Rev. 0, "Guidance for Post-Fire Safe Shutdown Analysis," dated May 2003.

NEI 04-06, Rev. G, "Guidance for Self-Assessment of Circuit Failure Issues", dated March 2004.

ITEM IlIl: OPERATOR MANUAL ACTIONS RULEMAKING Historical

Background:

The goal of the Operator Manual Actions Rulemaking is to revise Appendix R,Section III.G.2 and add new Section II.P to allow ex-Control Room operator manual actions as a Section IlI.G.2 compliance option if they conform to criteria to demonstrate their acceptability. The revised rule will provide reasonable assurance that post-fire operator manual actions will maintain the ability to achieve safe shutdown. Guidance for evaluating the actions will be provided in a Reg. Guide so that they can be uniformly evaluated by licensees and inspectors.

NRR Lead Section Chief: Sunil Weerakkody, SPLB, 415-2870 NRR Technical Contacts: Alex Klein, SPLB, 415-3477 Ray Gallucci, SPLB, 415-1255 David Diec, RPRP, 415-2834 RES Technical

Contact:

Jimi Yerokun, PRAB/DRAA, 415-6009

References:

SECY Paper 03-0100, uRulemaking Plan on Post-Fire Operator Manual Actions", dated June 2003.

SECY Paper 04-0233, "Proposed Rulemaking- Post-Fire Operator Manual Actions (RIN 3150 AH-54)

ITEM IV: EMERGING FIRE PROTECTION ISSUES RESOLUTION Historical

Background:

To facilitate the resolution of emerging issues, a protocol is established between the NEI/industry and the NRC. This process is intended to identify emerging fire protection generic issues, discuss priorities and schedules, and facilitate improved coordination without affecting NRC's oversight responsibility. Issues are tracked, prioritized, and given an action status by the responsible party.

Stakeholders are kept informed through publicly issued meeting summaries. This process was modeled after the protocol applied in the resolution of steam generator issues.

111

Hemyc Firewrap - Testing is needed on multiple configurations of 1-hour Hemyc fire wrap material to determine if the material can be rated as a one-hour fire barrier based on approved test methods. The work is being performed by RES and their contractors, with similar tests of 3-hour M.T. fire wrap to follow.

Epoxy Floor Coatings - Epoxy floor coatings are used in all nuclear power plants. There is a debate as to whether epoxy coating has been applied to floors in such a manner (numerous coats applied over the years, thickness greater than those tested, etc.) that it should be included in a plant' s combustible loading calculations.

RCP Seal Cooling - Some licensees have post-fire safe-shutdown procedures that induce a temporary loss of cooling to the reactor coolant pump (RCP) seals. Without test results or industry experience, the staff normally relies on manufacturers' design information to determine if a seal failure may occur or what leakoff rates actually may be. For Westinghouse RCP seals, two cases have been identified. New seals will leak, with no rupture, upon loss of cooling, while old seals will fail after about 30 minutes with no seal cooling. Some licensees, however, have not incorporated this guidance into their post-fire safe shutdown procedures.

CO2 - The most recent issue to emerge through the NEI/NRC Fire Protection Issue Management Protocol concerns the manual lockout of automatic carbon dioxide (CO2 ) fire suppression systems. CO2 fire suppression systems present a hazard to plant personnel if they accidently discharge. Consideration of this hazard must be weighed against the effectiveness of the system and the manual action, some licensees are utilizing to activate them.

Proposed Actions: See Milestone chart.

Originating Document: Not applicable.

Regulatory Assessment: See Historical Background.

Current Status: The contract has been let for the Heymc fire wrap test program, and the program for M.T.

fire wrap will follow later in 2005.

In accordance with the NEI/NRC Issue Management Protocol, NEI agreed to offer industry evaluation of the combustibility of epoxy coatings in nuclear plants. NEI has provided that input. NRC is reviewing NEl's recommendation and will provide a recommendation to the Inspection Program Branch (IIPB/DIPM/NRR).

If appropriate, NRC will issue a generic communication.

An Information Notice is being published on the RCP seal performance issue, and WOG is expected to provide their input to the NRC before the end of January 2005.

NEI is expected to issue a white paper on the CO2 fire suppression systems topic in January of 2005, at which time the Staff will further explore the technical merits of the issue and consider issuing a generic communication later in the year.

NRR Lead Section Chief: Sunil Weerakkody, SPLB, 415-2870 112

NRR Technical Contacts: Dan Frumkin, SPLB, 415-2280 Naeem lqbal, SPLB, 415-3346 Phil Qualls, SPLB, 415-1849 Robert Wolfgang, SPLB, 415-1624 Albert Wong, NMSS/OD, 415-7843 (on rotation in SPLB/DSSA)

RES Technical

Contact:

Mark Salley, PRAB/DRAA, 415-2840

References:

Regulatory Guide 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-informed Decisions On Plant-Specific Changes to the Licensing Basis", dated July 1998.

Administrative Letter 98-10, "Dispositioning of Technical Specifications That Are Insufficient to Assure Plant Safety", dated December 1998.

Information Notice 03-19, "Unanalyzed Condition of Reactor Coolant Pump Seal Leakoff Line During Postulated Fire Scenarios or Station Blackout", dated October 2003.

NRC Inspection Manual, Chapter 0609, Appendix F, "Determining Potential Risk Significance of Fire Protection and Post-Fire Safe Shutdown Inspection Findings", dated February 27, 2001.

NUREG-0800, Section 9.5.1, Rev. 4, "Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants Fire Protection Program", dated October 2003.

Test Plan for Heymc and M.T., Fire Barrier Performance, Package ML043210129.

NEI White Paper on Epoxy Coatings, June 28,2004, ML041900034.

NRC Staff Review of the Westinghouse Owners Group (WOG) Request for Enforcement Discretion for Reactor Coolant Pump (RCP) Seal Performance Findings in Triennial Fire Protection Inspections, November 12, 2004, ML043170324 ITEM V: REGULATORY TOOLS DEVELOPMENT Historical

Background:

Advancements have been made with several regulatory tools that the Staff can utilize to better ensure fire protection safety. For example, the fire protection SDP was updated to simplify the process, without reducing safety, by screening out very low risk findings that do not warrant further NRC involvement.

NUREG-1805 will be a key component in providing a simplified risk-informed methodology for use by inspectors to assess potential fire hazards that could cause critical damage to safe shutdown components.

The Office of Research is supporting the Fire PRA Requantification Study and the Fire Modeling Verification and Validation (V&V) Study. Both of these studies will provide acceptable methods to satisfy the requirements of NFPA 805.

113

Another advancement in regulatory tools is the American Nuclear Society (ANS) Fire PRA Standard which will be published in draft form in 2005. This new standard will provide criteria that can be applied in future fire PRA's, which can be used to support adoption of NFPA 805. The staff plans to endorse the ANS Fire PRA Standard, when it becomes available, through a revision to RG 1.200, "An Approach for Determining the Technical Adequacy of PRA Results For Risk-Informed Activities".

Proposed Actions: See Milestone chart.

Originating Document: Not applicable.

Regulatory Assessment: See Historical Background.

Current Status: The simplified risk-informed methodology was developed and issued for public comment as draft NUREG-1 805, "Fire Dynamics Tools (FDT') Quantitative Fire Hazard Analysis Methods for the U.

S. Regulatory Commission Fire Protection Inspection Program". Comments have been received and incorporated, as appropriate, and the final NUREG was issued in November 2004.

The Fire PRA Requantification Study (NUREG/CR-6850) is available in draft form now; the Fire Modeling V&V will be available in draft form by March 2005.

The ANS Fire PRA Standard will use portions of the Fire PRA Requantification and is not expected to be available until late 2005. NRR currently has a staff member on the Review Committee for the Standard who has direct input to the Writing Committee.

NRR Lead Section Chief: Sunil Weerakkody, SPLB, 415-2870 NRR Technical Contacts: Naeem lqbal, SPLB, 415-3346 James Downs, SPLB, 415-3194 RES Technical

Contact:

Mark Salley, PRAB/DRAA, 415-2840

References:

Dey, M., A. Hamins, and M. Steward, "International Collaborative Project to Evaluate Fire Models for Nuclear Power Plant Applications: Summary of 5th Meeting," NISTIR 6986, National Institute of Standards and Technology, Gaithersburg, Maryland, dated September 2003.

NUREG/CP-0170, "International Collaborative Project to Evaluate Fire Models for Nuclear Power Plant Applications: Summary of Planning Meeting," Held at University of Maryland College Park, Maryland, October 25-26, 1999, Office of Nuclear Regulatory Research, U.S. Nuclear Regulatory Commission, Washington, DC, dated March 2000.

114

NUREG/CP-0173, "International Collaborative Project to Evaluate Fire Models for Nuclear Power Plant Applications: Summary of 2nd Meeting," Held at Institute for Protection and Nuclear Safety, Fontenay-aux-Roses, France, June 19-20, 2000, Office of Nuclear Regulatory Research, U.S. Nuclear Regulatory Commission, Washington, DC, dated March 2001.

NUREG-1 805 (Advanced Copy), "Fire Dynamics Tools - Quantitative Fire Hazard Analysis Methods for the U.S. Nuclear Regulatory Commission Fire Protection Inspections Program", dated November 2004.

Draft NUREG/CR-6850, Vol. 1 & 2, "Fire PRA Methodology for Nuclear Power Facilities", dated October 2004.

115

DAVIS-BESSE LESSONS LEARNED TASK FORCE RECOMMENDATIONS REGARDING OPERATING EXPERIENCE PROGRAM EFFECTIVENESS TAC No. Description Last Update: 12/31/04 MB7280 Develop Operating Experience Lead Division: DIPM Action Plan Supporting Divisions: DE, DSSA, MB7347 Overall Assessment of Agency's & DLPM Operating Experience Program Supporting Offices: RES & Regions MB8220 Operating Experience Task Force Activities (NRR)

KC0056 Operating Experience Task Force Activities (RES)

MC2066 Operating Experience Task Force Plan Development MC3378 Operating Experience Program Implementation MB8034 Evaluation of Past Generic Communications Milestone Date (T=Target)

(C=Complete)

Part I - Operating Experience Program: Objective Phase

1. Form Task Force with Steering 03/03 (C) NRR/RES Committee and develop Charter. ML030900117

b. Identify desirable agency operating 04/03 (C) Task Force DIPM, experience program objectives and DLPM, DE, attributes, and DSSA, DET/RES, 2.a. Provide documented staff proposals of 04/03 (C) DRANRES, operating experience program objectives ML031200312 DSARE/RES, and attributes. ML031490535 Regions 2.b. Obtain executive management 05/03 (C) endorsement. ML031350156 116

Milestone Part II- Operating Experience Program: Assessment Phase

1. Define functional needs/areas and 9/03 (C) Task Force DIPM, processes to meet objectives and DLPM, DE, attributes. DSSA, DET/RES, DRAAIRES, DSARE/RES, Regions

2. Review and evaluate current processes. 11/03 (C) Task Force DIPM, ML033350063 DLPM, DE,

[LLTF 3.1.6(1)] DSSA, DET/RES, DRANRES, DSARE/RES, Regions

3. Identify areas for improvements. 11/03 (C) Task Force DIPM,

[LLTF 3.2.4(1)] ML033350063 DLPM, DE, DSSA, DET/RES, DRAAIRES, DSARE/RES, Regions

4. Task Force issues draft report. 09/03 (C) Task Force ML032740058

5. Task Force provides final report to 11/03 (C) Task Force Steering Committee documenting its ML033350063 specific program improvement proposals.

6. Steering Committee sends report back to 01/04 (C) Steering line management for implementation ML040080005 Committee detail.

01/04 (C) 6.a Responsible organizations achieve ML040560144 NRR/RES Regions consensus on proposals to implement.

Part IlIl - Operating Experience Program: Implementation Phase

1. Develop plan for program development 04/04 (C) NRR/RES Regions based on 6.a in Part II. ML041180024 OC0O 117

Milestone Date Lead Support (T=Target)

(C=Complete) 1.a Complete Operating Experience 12/04 (C) framework (Draft Management Directive/Handbook) [LLTF 3.1.6(2)]

1.b Other program enhancements: 03/03 (C)

(1) Handling of foreign operating LIC-401 experience [LLTF 3.1.6(3)]

(2) Strengthen inspection guidance 09/03 (C)

[LLTF 3.3.4(2)] IP 71152

2. Establish processes to monitor 03/05 (T) NRR/RES Regions effectiveness.

Part IV - Inspection Program Enhancements

1. Provide training and reinforce 12/03 (C) DIPM DE, expectations to NRC managers and staff DSSA, members to address the following areas: DET/RES, (1) maintaining a questioning attitude in Regions the conduct of inspection activities; (2) developing inspection insights stemming from the DBNPS event relative to symptoms and indications of RCS leakage; (3) communicating expectations regarding the inspection follow-up of the types of problems that occurred at DBNPS; and (4) maintaining an awareness of surroundings while conducting inspections. Training requirements should be evaluated to include the appropriate mix of formal training and on-the-job training commensurate with experience.

Mechanisms should be established to perpetuate these training requirements.

[LLTF 3.3.1(1)]

2. Implement actions to maintain NRC 12/03 (C) DIPM DE, expertise by ensuring that NRC inspector DSSA, training includes: (1) boric acid corrosion DET/RES, effects and control; and (2) PWSCC of Regions nickel based alloy nozzles. [LLTF 3.3.5(1)]

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==

Description:==

Initiatives to assess and improve the agency's reactor operating experience program has been initiated and ongoing for some time. Also, the report of the Davis-Besse Lessons Learned Task Force (LLTF), issued on September 30, 2002, contains a number of recommendations on operating experience program improvements. It is important to note that opportunities to improve access and use of operating experience information will continue in parallel with the systematic assessment of the agency's operating experience program described in this action plan.

Historical

Background:

Up until 1999, the Office of Analysis and Evaluation of Operational Data (AEOD) performed various activities pertinent to systematically collecting and evaluating operating experience, and communicating the lessons learned to the NRC staff and the regulated industry. With the abolishment of AEOD per SECY-98-228, 'Proposed Streamlining and Consolidation of AEOD Functions and Responsibilities," October 1, 1998, the roles and responsibilities of AEOD associated with the operating experience program were transferred to the Offices of Nuclear Regulatory Research (RES) and Nuclear Reactor Regulation (NRR). NRR was generally assigned the short-term operating experience reviews and RES long-term operating experience activities.

Since this time, both NRR and RES have recognized the need to make operating experience more efficiently available to users. RES has made substantial advances in making existing databases available through the internal web. These databases include licensee event reports (LERs), INPO's EPIX database, and monthly operating reports. RES uses these data to provide initiating event frequencies, safety system reliabilities, component failure probabilities, and common-cause failure parameter estimates, as well as related insights. The RES internal web page, for which significant further advances are already planned, will allow NRC staff easier and more timely access these estimates, related trends, and insights in a more timely manner. In addition, the RES internal web site will provide a new expanded LER search tool for use by NRC staff. It is planned that in April 2003, the accident sequence precursor (ASP) database will be accessible through the RES internal web site to the NRC staff. In September 2003, this will be followed by an expanded web site that will further integrate presently contained in separate databases and NUREG and NUREG/CR reports. NRR has similarly improved communications of its short term operating experience program outputs through web technology and is currently replatforming its events and assessment database.

However, despite individual program improvements, the effectiveness of the agency wide program has been questioned. Many believed that the current program activities should be more proactive, risk-informed, and integrated. Many also indicated that the insights gained and lessons learned from operating experience reviews should be better communicated to the users. In addition, both NRR and RES recognized that the governing agency policy, i.e., Management Directive 8.5, "Operational Safety Data Review," December 23,1997, and various guidance documents clearly needed updates. In late 2001, NRR created the Operating Experience Section (OES) under the Division of Regulatory Improvement Programs (DRIP). In late 2002, OES spearheaded an effort to assess the agency's overall operating experience program by soliciting support from various organizations responsible for agency's program activities. As a result, the Operating Experience Working Group has since been formed to better coordinate the multi-office effort for assessing and improving the agency's overall operating experience program.

One of the NRC follow-up actions to the Davis-Besse event was formation of a LLTF. The LLTF conducted an independent evaluation of the NRC's regulatory processes pertinent to the event in order to identify and recommend areas of improvement applicable to the NRC and the industry. A report summarizing their 119

findings and recommendations was published on September 30, 2002. The report contains several consolidated lists of recommendations. The LLTF report was reviewed by a Review Team (RT), consisting of several senior management personnel appointed by the EDO. The RT issued a report on November 26, 2002, endorsing all but two of the LLTF recommendations, and placing them into four overarching groups.

On January 3, 2003, the EDO issued a memo to the Directors of NRR and RES, tasking them with developing action plans for accomplishing High-Priority items in the four groups. This Action Plan addresses the assessment and improvement of the agency's operating experience program. It also addresses the recommendations of the Davis-Besse LLTF regarding operating experience program effectiveness. All of the seven High-Priority recommendations in "Assessment of Operating Experience, Integration of Operating Experience into Training, and Review of Program Effectiveness" grouping are included in this Action Plan.

Proposed Actions: This Action Plan describes the key high-level steps for the agency's operating experience overall program review, which goes beyond the scope of the Davis-Besse LLTF recommendations. This approach is expected to be more effective than addressing only the LLTF items separately from the overall operating experience program review. The High-Priority LLTF items are specifically designated in the milestones under appropriate Parts or steps to address the requirements prescribed in the January 3, 2003, Tasking Memorandum. The designated LLTF items represent only a subset of multiple activities for the corresponding milestone.

The milestones are grouped into Parts l, II, l1l, and IV.

Part I is associated with defining the objectives and attributes of the agency's desirable operating experience program and receiving the endorsement from the agency's executive management. An interoffice Task Force will be formed to perform the activities in Parts I and II. An interoffice (NRR, RES, and Regions) executive Steering Committee will also be formed to guide the Task Force activities. A Charter describing the goals and responsibilities of the Task Force will be jointly developed by the offices.

The purpose of this Task Force is to complete the milestones described in the objective and assessment Phases (Parts I and 11of this Action Plan) by December 31, 2003.

Part II describes the milestones associated with the assessment phase of the agency's overall operating experience program review. These assessment activities will be performed and completed by the Task Force. The scope of the assessment phases will include, but is not necessarily limited to, those operating experience functions identified by SECY-98-228. The output of the assessment activities will be the development of specific proposals for improvement in functional areas to effectively achieve the objectives established in Part I. The Task Force will issue a draft report for review when its preliminary observations, conclusions, and proposals are identified. The Task Force will subsequently provide a final report to the Steering Committee documenting its specific program improvement proposals and the basis for those proposals. The Steering Committee will make recommendations to the offices on improvements to be made and office management will make appropriate assignments. The target date for the Part II milestones is December 31, 2003.

The Part IlIl improvements would include a number of actions that could significantly improve the agency's overall operating experience program effectiveness. These actions will be taken by line organizations in accordance with an implementation plan in response to the recommendations by the Steering Committee.

The implementation plan is expected to contain both short-term and long-term improvements. The short-term improvements are expected to be implemented starting in early 2004 and long-term improvements in 120

mid- to late 2004. Actions are expected to require significant interoffice coordination and interaction. If the improvements requires significant changes to the policy, resource, or organizational structure, interactions with the Commission would be necessary. Meetings and communications with both internal and external stakeholders, e.g., INPO, are also expected and encompassed within the scope of the milestones listed in Parts II and Ill. The target date for completion all the Part Ill milestones is December 31, 2004.

Part IV lists the two inspection-related High-Priority LLTF items that are focused on enhancing inspection activities.

Originating Documents:

Memorandum from Travers, W.D. to Collins, S. and Thadani, A. C., dated January 3, 2003, "Actions Resulting From The Davis-Besse Lessons Learned Task Force Report Recommendations."

(ML023640431)

Memorandum from Paperiello, C.J. to Travers, W.D., dated November 26, 2002, "Senior Management Review of the Lessons-Learned Report of the Davis-Besse Nuclear Power Station Reactor Pressure Vessel Head." (ML023260433)

Memorandum from Howell, A.T. to Kane, W.F., dated September 30, 2002, "Degradation of the Davis-Besse Nuclear Power Station Reactor Pressure Vessel Head Lessons-Learned Report." (ML022740211)

Regulatory Assessment: The agency performs a broad range of activities that relate to collection, assessment, feedback, and dissemination of nuclear reactor operating experience. The main purpose of these activities is to generate valuable insights and lessons learned from operating experience and provide feedback to the NRC regulatory programs and the industry. The output of these activities should positively influence both the NRC regulatory programs and the nuclear industry performance. These operating experience program activities provide mechanisms for an independent assessment of the effectiveness of the current NRC regulatory programs and activities and generate long-term, historical, and objective perspectives on individual nuclear power plant and industry performance.

The LLTF recommended that the effectiveness of the current operating experience program be evaluated.

As stated earlier, a systematic review of the overall operating experience program has been ongoing and would proceed according to this Action Plan.

Again, the regulatory basis for the agency's current operating experience functions generally stems from the roles and responsibilities defined in SECY-98-228. Any changes in the organizational and/or functional responsibilities defined in this SECY will likely require Commission consultation.

Current Status: All Part I (Objective Phase) activities are complete. The Operating Experience Task Force was formed, and completed development of program objectives and attributes, which were endorsed by the Steering Committee.

The Part II (Assessment Phase) activities are complete. The Task Force delivered its draft report to the Steering Committee in September. After incorporating review comments from the Steering Committee, the final report was delivered in November. The Steering Committee sent the report to line management in January with 24 direction setting recommendations for implementation.

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The Part IlIl (Implementation Phase) activities are in progress. The plan for program development was completed in April 2004. Development of the Operating Experience framework (draft Management Directive/Handbook) was completed in December 2004. Implementation of the new processes by NRR and RES commenced as soon as the framework was approved. An NRR Office Instruction has been developed to implement the draft Management Directive and Handbook. After reviewing program enhancements instituted to date, it was determined that LLTF recommendations 3.1.6(3) and 3.3.4(2) were adequately addressed and can be considered complete.

Inspection program enhancements in Part IV were completed as scheduled. A web-based training process was initiated, by which inspectors log on and conduct self-paced training. A record of personnel who complete the training is available for management review and follow-up. Training modules on boric acid corrosion and primary water stress corrosion cracking were issued on the system. Also, a training program based on the Columbia shuttle accident, which emphasizes expectations on maintaining a questioning attitude, awareness of surroundings, follow-up to problems, etc., was presented at inspector counterpart meetings and added to the web-based training.

Contacts:

NRR Technical

Contact:

Terrence Reis, IROB, 415-3281 OE Task Force Leader: Charles Ader, RES/DSARE, 415-0135 DSSA Lead

Contact:

Michael Johnson, SPSB, 415-3183 DIPM Lead

Contact:

Patrick Hiland, IROB, 415-1161 DLPM Lead

Contact:

Edwin Hackett, LPD II, 415-1485 DE Lead

Contact:

Goutam Bagchi, 415-3005 DET/RES Lead

Contact:

Nilesh Chokshi, 415-0190 DRAAIRES Lead

Contact:

Patrick Baranowsky, OERAB, 415-7493 DSARE/RES Lead

Contact:

Jose Ibarra, ARREB, 415-8742 Regional Offices: Charles Casto, Region II, 404-562-4600

References:

Management Directive 8.5, "Operational Safety Data Review," December 23,1997.

SECY-98-228, "Proposed Streamlining and Consolidation of AEOD Functions and Responsibilities,"

October 1, 1998.

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Table 1 LLTF Report Recommendations (High Priority)

RECOMMENDATION RECOMMENDATION NUMBER 3.1.6(1) The NRC should take the following steps to address the effectiveness of its programs involving the review of operating experience: (1)evaluate the agency's capability to retain operating experience information and to perform longer-term operating experience reviews; (2)evaluate thresholds, criteria, and guidance for initiating generic communications; (3)evaluate opportunities for additional effectiveness and efficiency gains stemming from changes in organizational alignments (e.g., a centralized NRC operational experience "clearing house"); (4)evaluate the effectiveness of the Generic Issues Program; and (5)evaluate the effectiveness of the internal dissemination of operating experience to end users.

3.1.6(2) The NRC should update its operating experience guidance documents.

3.1.6(3) The NRC should enhance the effectiveness of its processes for the collection, review, assessment, storage, retrieval, and dissemination of foreign operating experience.

3.2.4(1) The NRC should assess the scope and adequacy of its requirements governing licensee review of operating experience.

3.3.4(2) The NRC should strengthen its inspection guidance pertaining to the periodic review of operating experience. The level of effort should be changed, as appropriate, to be commensurate with the revised guidance.

3.3.1(1) The NRC should provide training and reinforce expectations to NRC managers and staff members to address the following areas:

(1)maintaining a questioning attitude in the conduct of inspection activities; (2)developing inspection insights stemming from the DBNPS event relative to symptoms and indications of RCS leakage; (3)communicating expectations regarding the inspection follow-up of the types of problems that occurred at DBNPS; and (4)maintaining an awareness of surroundings while conducting inspections. Training requirements should be evaluated to include the appropriate mix of formal training and on-the-job training commensurate with experience. Mechanisms should be established to perpetuate these training requirements.

3.3.5(1) The NRC should maintain its expertise in the subject areas by ensuring that NRC inspector training includes: (1)boric acid corrosion effects and control; and (2) PWSCC of nickel based alloy nozzles.

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ATTACHMENT 2 GENERIC COMMUNICATION AND COMPLIANCE ACTIVITIES

Open Generic Communication TACs (PA No. 101122CA/B)

Summary Report as of 1213112004 TAC NO. TAC TRE AGE LEAD OHS MC3721 BL: Spent Fuel Rod Accountability (Tuttle-NSIR/Petrone-DIPM) .6 NSIR MC2470 GL: Steam Generator Tube Integrity and Associated Technical Specifications (Karwoski-DE/Markley-DIPM) 10 DE MC2590 GL: Ultrasonic Flow Meters (Ahmed-DE/Markley-DIPM) 9 DE MC5142 IN: Blocked Floor Drains & Non-Water-Tight Equipment Floor Plugs Increase Flooding Risk (Blamey-RlITelson-DIPM) 2 RI MC5250 IN: Pressure Boundary Leakage Identified on Steam Generator Bowl Drains (Black-DE/Hodge-DIPM) 1 DE MC5138 IN: Seismic Gap Fire Barrier Inadequate Design and Installation (ReyesMaldonado-DSSA/Rini-DIPM) 2 DSSA MC5225 IN: Steam Generator Tube Crack Indication Issues (Karwoski-DE/Laura-DIPM) I DE MC5178 IN: Three Unit Trip and Loss of Offsite Power at Palo Verde (Pal-DE/Hodge-DIPM) 2 DE.

MC5002 RIS: Changes to Notice of Enforcement Discretion (NOED) Process and Staff Guidance (Berkow-DLPMWMarkley-DIPM) 2 DLPM MC3977 RIS: Clarifying the Process for Making Emergency Plan Changes (Williams-NSIRIPetrone-DIPM) 5 NSIR MC2262 RIS: GL 91-18. Rev 2-Guldance on Operability & Resol of Degraded & Non-CnfrmIng Conditions (Boyce-DIPMWMarkley- 6 DIPM DIPM)

MC4220 RIS: Guidance for Establishing and Maintaining a Safety Conscious Work Environment (Jarriel-OE/Petrone-DIPM) 5 OE MC5251 RIS: Guidance on Prot of Unattended Openings That Intersect a Security Boundary or Area (Tardiff-NSIRIMarkley- 1 NSIR DIPM)

MC5381 RIS: Issuance of NRC Management Directive 8.17, Licensee Complaints Against NRC Employees (Allsopp- 1 DIPM DlPM/Markley-DIPM)

MC3628 RIS: Performance of Manual Actions to Satisfy the Reqmts of 10CFR Part 50, App R. Sec III.G.2 (Klein-DSSAJPetrone- 7 DSSA DIPM)

MC4577 RIS: Regulatory Issues Regarding Criticality Analyses For Spent Fuel Pools & ISFSls (Taylor-DSSANMarkley-DIPM) 3 DSSA MC4310 RIS: RIS 2004-003, Rev 1: Risk-Informed Approach For Post-Fire Safe-Shutdown Circuit Insps (Frumkin- 4 DSSA DSSAIMarkley-DIPM)

MC5252 RIS: Scope of For-Cause Fitness-for-Duty Testing Required by 10 CFR 26.24(a)(3) (Canady-NSIRIMarkley-DIPM) 1 NSIR Tuesday, January 11,2005 Page 1 of 1

Closed Generic Communication TACs (PA No. 101122CA/B)

Summary Report (1010112004 - 12/31/2004)

TAC NO. TAC TIE STATUS AGE TAC CLOSED LEAD ORE MC2340 BL: Inspection of Primary System Alloy 82/182 Piping Butt Welds (Mitchell-DE/Markley-DIPM) WI 8 11/30/2004 DE MC2341 GL: Assmt & Dispos of Impact of PWSCC of Alloy 82t182 Welds on Leak-Before-Break Analyses (Mitchell- WI 8 11/5/2004 DE DEtPetrone-DIPM)

MC4223 IN: Additional Adverse Effect of Boric Acid Leakage Upset of Post-Accident Coolant Leakage (Hodge-DIPM/) C 4 12/8/2004 DIPM MC3722 IN: Operator Medical Issues (Guenther-DIPMtMarkley-DIPM) C 6 12/812004 DIPM MC4467 IN: Problems Associated w/ Back-up Pwr Supplies to Emerg Response Facilities & Equipment (Flemming- C 2 11/19/2004 NSIR NSIRtPetrone-DIPM)

MC3958 RIS: Availability of Revision 9 to NUREG-1 021 (Guenther-DIPM/Petrone-DIPM) WI 2 10/4/2004 DIPM MC3846 RIS: Clarif on Use of Later Editions & Addenda to ASME Sec Xl for Repair/Replacement Activities (Tsao- C 4 11t2t2004 DE DE/Petrone-DIPM)

MC3844 RIS: Clarif Providg Access to Autho Nucl Inservice Insp & NRC Authorized Alter ASME Code Rqmts (Tsao- C 5 12/22/2004 DE DE/Petrone-DIPM)

MC3713 RIS: Emergency Preparedness Issues: Post-9/1l (Anderson-NSIR/Petrone-DIPM) C 6 11/2/2004 NSIR MC4217 RIS: Focusing Resources in NRR as a Result of Review of Security Plan Changes (Licata-DLPMIPetrone-DIPM) C 2 10/4/2004 DLPM Tuesday. January 11 2005 Page I of I