ML051710075

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

ML051710075
Person / Time
Issue date:	08/02/2005
From:	Mckenna E Division of Regulatory Improvement Programs
To:	Fertel M Nuclear Energy Institute
Sweeney B NRC/NRR/DRIP/RPRP, 415-1029
References
Download: ML051710075 (123)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION q j)WASHINGTON, D.C. 2055-0001 August 2, 2005 Mr. Marvin S. Fertel, Senior Vice President

& Chief Nuclear Officer Nuclear Energy Institute 1776 1 Street NW Suite 400 Washington, D.C. 20006-3708

SUBJECT:

ISSUANCE AND NOTIFICATION OF STREAMLINING EFFORT AND ELIMINATION OF PAPER COPY DISTRIBUTION OF.THE DIRECTOR'S QUARTERLY STATUS REPORT In an effort to reduce duplication of reports, the U.S. Nuclear Regulatory Commission (NRC) is currently streamlining the Director's Quarterly Status Report (DQSR). In addition to this, we are eliminating paper copy distribution and this will be the last "hard copy" of the DQSR that you will receive. In the future, you will be provided with an external website address where you can easily retrieve the DQSR.

Please send an e-mail to bis3(inrc.oov and provide your name and e-mail address so that you can be notified electronically when quarterly updates have been made to the DQSR and are available in ADAMS/posted to the external NRC website.

If you have any questions, please contact Beverly Sweeney via e-mail at bis3(Rnrc.aov or call her on 301-415-1029.

Sincerely, Eileen M. McKenna, Acting Program Director Policy and Rulemaking Program Division of Regulatory Improvement Programs Office of Nuclear Reactor Regulation

UNITED STATES NUCLEAR REGULATORY COMMISSION A WASHINGTON, D.C. 20555-0001

• • • August 2, 2005 Mr. R. P. LaRhette Institute of Nuclear Power Operations 700 Galleria Parkway Atlanta, GA 30339-5979

SUBJECT:

ISSUANCE AND NOTIFICATION OF STREAMLINING EFFORT AND ELIMINATION OF PAPER COPY DISTRIBUTION OF THE DIRECTOR'S QUARTERLY STATUS REPORT In an effort to reduce duplication of reports, the U.S. Nuclear Regulatory Commission (NRC) is currently streamlining the Director's Quarterly Status Report (DQSR). In addition to this, we are eliminating paper copy distribution and this will be the last "hard copy" of the DQSR that you will receive. In the future, you will be provided with an external website address where you can easily retrieve the DQSR.

Please send an e-mail to bis3(Rnrc.gov and provide your name and e-mail address so that you can be notified electronically when quarterly updates have been made to the DQSR and are available in ADAMS/posted to the external NRC website.

If you have any questions, please contact Beverly Sweeney via e-mail at bis36)nrc.qov or call her on 301-415-1029.

Sincerely,

&,"QA)x )lC t Eileen M. McKenna, Acting Program Director Policy and Rulemaking Program Division of Regulatory Improvement Programs Office of Nuclear Reactor Regulation

t, ,.sUNITED STATES 0 e 3NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 August 2, 2005 Mr. Lee Watkins Assistant Manager For High Level Waste U.S. DOE P.O. Box A Aiken, SC 29892

SUBJECT:

ISSUANCE AND NOTIFICATION OF STREAMLINING EFFORT AND ELIMINATION OF PAPER COPY DISTRIBUTION OF THE DIRECTOR'S QUARTERLY STATUS REPORT In an effort to reduce duplication of reports, the U.S. Nuclear Regulatory Commission (NRC) is currently streamlining the Director's Quarterly Status Report (DQSR). In addition to this, we are eliminating paper copy distribution and this will be the last "hard copy" of the DQSR that you will receive. In the future, you will be provided with an external website address where you can easily retrieve the DQSR.

Please send an e-mail to bis3e-nrc.aov and provide your name and e-mail address so that you can be notified electronically when quarterly updates have been made to the DQSR and are available in ADAMS/posted to the external NRC website.

If you have any questions, please contact Beverly Sweeney via e-mail at bis3(i.nrc.Qov or call her on 301-415-1029.

Sincerely, Eileen M. McKenna, Acting Program Director Policy and Rulemaking Program Division of Regulatory Improvement Programs Office of Nuclear Reactor Regulation

_0A ,UNITED STATES W) D oNUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 August 2, 2005 Mr. S. Scott Office of Nuclear Safety, DOE Century 21 Building (E-H72) 19901 Germantown Road Germantown, MD 20874-1290

SUBJECT:

ISSUANCE AND NOTIFICATION OF STREAMLINING EFFORT AND ELIMINATION OF PAPER COPY DISTRIBUTION OF THE DIRECTOR'S QUARTERLY STATUS REPORT In an effort to reduce duplication of reports, the U.S. Nuclear Regulatory Commission (NRC) is currently streamlining the Director's Quarterly Status Report (DQSR). In addition to this, we are eliminating paper copy distribution and this will be the last "hard copy" of the DQSR that you will receive. In the future, you will be provided with an external website address where you can easily retrieve the DQSR.

Please send an e-mail to bis3a-nrc.oov and provide your name and e-mail address so that you can be notified electronically when quarterly updates have been made to the DQSR and are available in ADAMS/posted to the external NRC website.

If you have any questions, please contact Beverly Sweeney via e-mail at bis3 Wnrc. ov or call her on 301-415-1029.

Sincerely, Eileen M. McKenna, Acting Program Director Policy and Rulemaking Program Division of Regulatory Improvement Programs Office of Nuclear Reactor Regulation

UNITED STATES 0o NUCLEAR REGULATORY COMMISSION v WASHINGTON, D.C. 20555-0001 August 2, 2005 Mr. Bob Borsum 1700 Rockville Pike, Suite 525 Rockville, MD 20852

SUBJECT:

ISSUANCE AND NOTIFICATION OF STREAMLINING EFFORT AND ELIMINATION OF PAPER COPY DISTRIBUTION OF THE DIRECTOR'S QUARTERLY STATUS REPORT In an effort to reduce duplication of reports, the U.S. Nuclear Regulatory Commission (NRC) is currently streamlining the Director's Quarterly Status Report (DQSR). In addition to this, we are eliminating paper copy distribution and this will be the last 'hard copy" of the DQSR that you will receive. In the future, you will be provided with an external website address where you can easily retrieve the DQSR.

Please send an e-mail to bis3(nrc.cIov and provide your name and e-mail address so that you can be notified electronically when quarterly updates have been made to the DQSR and are available in ADAMS/posted to the external NRC website.

If you have any questions, please contact Beverly Sweeney via e-mail at bis3 -nrc.gov or call her on 301-415-1029.

Sincerely, Eileen M. McKenna, Acting Program Director Policy and Rulemaking Program Division of Regulatory Improvement Programs Office of Nuclear Reactor Regulation

s ,x, UNITED STATES t 3NUCLEAR REGULATORY COMMISSION Z WASHINGTON, D.C. 20555-0001 August 2, 2005 Ms. Norena G. Robinson, Licensing Technician Nebraska Public Power District Cooper Nuclear Station P.O. Box 98 Brownsville, NE 68321

SUBJECT:

ISSUANCE AND NOTIFICATION OF STREAMLINING EFFORT AND ELIMINATION OF PAPER COPY DISTRIBUTION OF THE DIRECTOR'S QUARTERLY STATUS REPORT In an effort to reduce duplication of reports, the U.S. Nuclear Regulatory Commission (NRC) is currently streamlining the Director's Quarterly Status Report (DQSR). In addition to this, we are eliminating paper copy distribution and this will be the last "hard copy" of the DQSR that you will receive. In the future, you will be provided with an external website address where you can easily retrieve the DQSR.

Please send an e-mail to bis3(@nrc.gov and provide your name and e-mail address so that you can be notified electronically when quarterly updates have been made to the DQSR and are available in ADAMS/posted to the external NRC website.

If you have any questions, please contact Beverly Sweeney via e-mail at bls3 -nrc. ov or call her on 301-415-1029.

Sincerely,

'i )A g1 Eileen M. McKenna, Acting Progra Director Policy and Rulemaking Program Division of Regulatory Improvement Programs Office of Nuclear Reactor Regulation

- - i .

UNITED STATES m 3NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 August 2, 2005 Ms. Nancy G. Chapman, SERCH Manager Bechtel Power Corporation 5275 Westview Drive Frederick, MD 21703-8306

SUBJECT:

ISSUANCE AND NOTIFICATION OF STREAMLINING EFFORT AND ELIMINATION OF PAPER COPY DISTRIBUTION OF THE DIRECTOR'S QUARTERLY STATUS REPORT In an effort to reduce duplication of reports, the U.S. Nuclear Regulatory Commission (NRC) is currently streamlining the Director's Quarterly Status Report (DQSR). Inaddition to this, we are eliminating paper copy distribution and this will be the last "hard copy" of the DQSR that you will receive. Inthe future, you will be provided with an external website address where you can easily retrieve the DQSR.

Please send an e-mail to bis3a)nrc.qov and provide your name and e-mail address so that you can be notified electronically when quarterly updates have been made to the DQSR and are available in ADAMS/posted to the external NRC website.

If you have any questions, please contact Beverly Sweeney via e-mail at bis3 nrc.cov or call her on 301-415-1029.

Sincerely, Eileen M. McKenna, Acting Program Director Policy and Rulemaking Program Division of Regulatory Improvement Programs Office of Nuclear Reactor Regulation

A ,UNITED STATES i 0 NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 August 2, 2005 Mr. Rod Buckles Client Manager, LIS, NIIS and TRENDS SCIENTECH, Inc.

Suite 300 2650 McCormick Drive Clearwater, Florida 33759-1049

SUBJECT:

ISSUANCE AND NOTIFICATION OF STREAMLINING EFFORT AND ELIMINATION OF PAPER COPY DISTRIBUTION OF THE DIRECTOR'S QUARTERLY STATUS REPORT In an effort to reduce duplication of reports, the U.S. Nuclear Regulatory Commission (NRC) is currently streamlining the Director's Quarterly Status Report (DQSR). In addition to this, we are eliminating paper copy distribution and this will be the last "hard copy' of the DQSR that you will receive. In the future, you will be provided with an external website address where you can easily retrieve the DQSR.

Please send an e-mail to bis3enrc.gov and provide your name and e-mail address so that you can be notified electronically when quarterly updates have been made to the DQSR and are available in ADAMS/posted to the external NRC website.

If you have any questions, please contact Beverly Sweeney via e-mail at bis3 -nrc.pov or call her on 301-415-1029.

Sincerely, Eileen M. McKenna, Acting Program Director Policy and Rulemaking Program Division of Regulatory Improvement Programs Office of Nuclear Reactor Regulation

August 2, 2005 Mr. Marvin S. Fertel, Senior Vice President

& Chief Nuclear Officer Nuclear Energy Institute 1776 I Street NW Suite 400 Washington, D.C. 20006-3708

SUBJECT:

ISSUANCE AND NOTIFICATION OF STREAMLINING EFFORT AND ELIMINATION OF PAPER COPY DISTRIBUTION OF THE DIRECTOR'S QUARTERLY STATUS REPORT In an effort to reduce duplication of reports, the U.S. Nuclear Regulatory Commission (NRC) is currently streamlining the Director's Quarterly Status Report (DQSR). In addition to this, we are eliminating paper copy distribution and this will be the last "hard copy" of the DQSR that you will receive. In the future, you will be provided with an external website address where you can easily retrieve the DQSR.

Please send an e-mail to bis3anrc.oov and provide your name and e-mail address so that you can be notified electronically when quarterly updates have been made to the DQSR and are available in ADAMS/posted to the external NRC website.

If you have any questions, please contact Beverly Sweeney via e-mail at bis3()nrcxqov or call her on 301-415-1029.

Sincerely, Eileen M. McKenna, Acting Program Director Policy and Rulemaking Program Division of Regulatory Improvement Programs Office of Nuclear Reactor Regulation Identical letters sent to: Multiple Addressees, see attached list of addressees Distribution:

ADAMS RPRP R/F WKane, EDO (RidsEdoMailCenter) JEDyer, NRR (RidsNrrOd)

DBMatthews, NRR (RidsNrrDrip) LBMarsh, NRR (RidsNrrDlpm)

BABoger, NRR (RidsNrrDipm) MMayfield, NRR (RidsNrrDe)

JLyons, NRR (RidsNrrDssa) CCarpenter, NRR (RidsNrrPmas)

SCoffin, NRR EMMcKenna, NRR JFoster, NRR BJSweeney, NRR RCEmrit, RES RidsRgl MailCenter RidsRg2MailCenter RidsRg3MailCenter RidsRg4MailCenter ADAMS ACCESSION NUMBER: ML05170075 DOCUMENT NAME: DIST.WPD ADAMS DOCUMENT TITLE: Public Version of July 2005 Director's Quarterly Status Report To receive a cony of this document. Indicate In the box: 'C' - Copy without atnachment/enclosure 'E' Copy with attachmentlenclosure 'N' - No copy OFFICE RPRP:DRIP RORP:ORIP SC:RPRPDIP SC:RPRP:DRIP (A)PD:RPRP:DRPl NAME aSweeney-bs JFoster i EMcKe4/ipM SCod EMcKieX'll I DATE 0V M 0X/ 081505 JO 5 081 5 OFIIA RCbCOPY

Addressees - Letter dated August 2,2005

Subject:

MULTIPLE ADDRESSEE LIST Mr. R. P. LaRhette Institute of Nuclear Power Operations 700 Galleria Parkway Atlanta, GA 30339-5979 Mr. Lee Watkins 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 Ms. Nancy G. Chapman, SERCH Manager Bechtel Power Corporation 5275 Westview Drive Frederick, MD 21703-8306 Mr. Rod Buckles Client Manager, LIS, NIIS and TRENDS SCIENTECH, Inc.

Suite 300 2650 McCormick Drive Clearwater, Florida 33759-1049

DIRECTOR'S STATUS REPORT on GENERIC ACTIVITIES Action Plans Generic Communication and Compliance Activities APRIL 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., Offsite Power Concerns), and issues related to regulatory flexibility and improvements (e.g., Significance Determination Process (SDP) Improvement). 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 ISSUES .................... 1 DAVIS-BESSE LESSONS LEARNED TASK FORCE RECOMMENDATIONS REGARDING ASSESSMENT OF BARRIER INTEGRITY REQUIREMENTS (FINAL UPDATE) ..................... 13 DIPM SIGNIFICANCE DETERMINATION PROCESS (SDP)

IMPROVEMENT ............................................... 22 DLPM STEAM GENERATORS ................ 41 DAVIS-BESSE LESSONS LEARNED TASK FORCE RECOMMENDATIONS REGARDING STRESS CORROSION CRACKING ................................................... 56 DSSA PWR SUMP PERFORMANCE . .............................. 67 GENERIC SAFETY ISSUE (GSI) 189 - SUSCEPTIBILITY OF ICE CONDENSER AND MARK III CONTAINMENTS TO EARLY FAILURE FROM HYDROGEN COMBUSTION DURING A SEVERE ACCIDENT ................................................... 75 CONTROL ROOM HABITABILITY .............................. 83 FIRE PROTECTION PROGRAM ............................... 90 PHASED APPROACH TO PRA QUALITY .......................... 101

OFFSITE POWER ISSUES TAC No. MC3380 Last Update: 06/30/05 Lead Division: DE Supporting Divisions: DLPM, DSSA, and DIPM Supporting Office: RES GROUP ONE ISSUES 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)

(internal/external).

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)

9. Using risk significance of each issue as a guide, develop an NRR/DE 07/30/04 (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 04/26/05 (C) 1

Milestones Responsibility Estimated Completion Date

11. Establish interfaces with grid reliability organizations. NRR/DE 12/06

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 02/28/05 (C) models for spectrum of plants (draft report for internal/external review).

c. Review SBO considerations and determine if regulatory NRR/DE/EEIB 08/15/04 (C) actions are needed.

14. Incorporate unresolved concerns into Group Three NRR/DE/EEIB 08/15/04 (C) concerns 2

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

1. Receive NERC audit reports. NRRIDE 06/30/04 (C)

2. Assess the information provided in the audit reports to NRR/DE 07/09/04 (C) ascertain whether NRC issues have been addressed.

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

Commission.

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

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

6 Meet with NERC to discuss their response. NRR/DE 08/20/04 (C)

7. Re-assess any additional NERC input. NRR/DE 09/03/04 (C)

8. Develop Group Two disposition document if different from NRR/DE item 5 - Group Two disposition was the same. NIA

9. Incorporate unresolved concerns into Group Three NRRIDE 09/17/04 (C) concerns.

3

GROUP THREE ISSUES 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 issues.

2. Organize issues by topic as described in Activity 9 for the NRR/DE 08/30/04 (C)

Group One concerns.

3. Determine staff to be included in review groups. NRR/DE 08/30/04 (C)

4. Determine NRR leads for review groups NRR/DE 08/30/04 (C)

5. Incorporate Group Two issues not resolved in Group One NRR/DE 09/17/04 (C) or Two assessments into Group Three issues .

6. Develop schedule for review groups to review issues. NRR/DE, RES, 02/03/05 (C)

(Stakeholders input)

7. Review groups obtain information necessary to address NRR/DE, RES, 01/31/05 (C) issues . (Stakeholders input)

8. Review groups assess issues including management NRR/DE, 02/28/05 (C) briefings on LOOP risk analyses and EDG reliability and RES/DRAA, issue draft LOOP risk report for review. (Stakeholders input)

9. Review group members develop regulatory position to NRR/DE, RES 04/12/05 (C) present to Commission - Determined a regulatory position in not necessary at this time.

10. Commission briefing NRR/DE 04/26/05 (C)

11. Final status of action plan on grid issues to Commission. NRR/DE 07/14/05 (T)

12. Resolve public comments and issue as final - Generic NRR/DE/EEIB 12/15/05 (T)

Letter (GL) 2005-XX; "Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power."

13. Evaluate the results of the final GL to determine which NRR/DE/EEIB 12/06 (T) regulatory requirements need to be revised to ensure safe NPP operation, including rulemaking if appropriate.

14. Collection and on-going assessment of impact of grid NRR/DE/EEIB 12/06 (T) operating experience and data by NERC and the NRC. RES/DSARE

==

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).

4

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.

5

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 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.

6

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 Appendices (ADAM Accession No. ML051750337) were signed by both the NRC and NERC on June 2, 2005.

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 517th meeting on November 4, 2004. A transcript can be found on pages 286 through 368 at the NRC public website.

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). The staff closed Issue 24 in a memorandum dated January 6, 2005 (ADAMS Accession No. ML050180204). The staff closed Issues 36 and 37 in a memorandum dated February 2, 2005 (ADAMS Accession No. ML0500340376). The staff closed Issues 26, 32, 42, 43, and 44 in a memorandum dated February 9, 2005 (ADAMS Accession No. ML050400076). The staff closed Issue 3 in a memorandum dated February 9, 2005 (ADAMS Accession No. ML050410292). The staff closed Issues 1, 6, and 7 in a memorandum dated February 9, 2005 (ADAMS Accession No. ML050410318). The staff closed Issues 4, 8,12, 13, 14, 21, 22, 23, 27, 31, 39, 40, 41, 46, and 47 in a memorandum dated February 9, 2005 (ADAMS Accession No. ML050410338). The staff addressed Issue 29 in a memorandum dated February 10, 2005 (ADAMS Accession No. ML050540252). The staff addressed Issue 25 in a memorandum dated March 12, 2005 (ADAMS Accession No. ML050740179).

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 the NRC public website. The transcript pages pertaining to grid reliability are 12-14, 25-26, and 48-49. The complete transcript can be found at the NRC public website. 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 expired 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 LOOP durations have increased. Various additional topics of interest were also addressed. These topics include comparisons with results from other studies; seasonal impacts on LOOP frequencies, and consequential LOOPs. Finally, additional engineering analyses of the LOOP data were presented. This information is needed in probabilistic risk assessment models of U.S. commercial nuclear power plants to accurately model current risk from LOOP and associated station blackout scenarios.

In January 2005, the staff began processing a generic communication in order to meet SRM M041209.

The generic communication is contained in ADAMS Accession No. ML050310139 and the Committee To Review Generic Requirements (CRGR) memorandum is contained in ADAMS accession No. ML050390189. On April 12, 2005, in accordance with SRM M041209, the staff issued the draft generic letter for public comment in the Federal Register (70 FR 19125) to request that licensees submit 8

information to the staff concerning the status of their compliance with certain NRC regulations (ADAMS Accession No. ML050810504). . The public comment period closed on June 13, 2005. A total of 14 comments were received. The staff is currently reviewing the comments to meet the December 15, 2005, issuance of the final GL.

On February 28, 2005, the staff issued in the Federal Register (70 FR 9682) a notice of availability of the RES draft report entitled, "Station Blackout Risk Evaluation for Nuclear Power Plants," for comment. The comment period expires on April 15, 2005. This report is an update of several previous reports analyzing the risk from loss of offsite power and subsequent station blackout events at U.S. commercial nuclear power plants. The risk measure used is core damage frequency (CDF). Standardized plant analysis risk (SPAR) models developed by the U.S. Nuclear Regulatory Commission, covering the 103 operating commercial nuclear power plants, were used to evaluate the risk. CDF results indicating contributions from station blackout (SBO) scenarios and other LOOP scenarios are presented for each of the 103 plants, along with plant class and industry averages. In addition, a comprehensive review of emergency diesel generator (EDG) performance was performed to obtain current estimates for input to the SPAR models. Overall results indicate that CDFs for LOOP and SBO are lower than previous estimates. Contributing to this risk reduction is an improvement in EDG performance.

During the 520th meeting held on March 3-5, 2005, of the ACRS, the ACRS plans to review the generic communication after the public comment period (ADAMS Accession No. ML050680282).

The staff sponsored a grid reliability breakout session at the Regulatory Information Conference on March 8, 2005. The summary and presentation slides are available on the NRC web page.

NEI made a drop-in visit on April 15, 2005, with Commissioner McGaffigan and Commissioner Lyons regarding grid reliability. The briefing package is located in ADAMS No. ML050830250.

The Commission requested a meeting regarding grid reliability. The Commission meeting was held on April 26, 2005. Documents including the meeting slides and transcripts can be found on the NRC public website.

The staff issued Temporary Instruction (TI) 2515/163, 'Operational Readiness of Offsite Power," on May 2, 2005. The objective of the TI is confirm, through inspections and interviews, the operational readiness of offsite power systems in accordance with NRC requirements. This TI will also ensure the readiness of nuclear power plants to cope with the potential challenges by power outage events during the summer of 2005. All responses were received from the resident inspectors by June 1, 2005. Staff is currently reviewing the results from the TI.

The staff has been following grid reliability activities of the following organizations: North American Electric Reliability Council (NERC), Federal Energy Regulatory Commission (FERC), Department of Homeland Security (DHS), Nuclear Energy Institute (NEI), and Institute of Nuclear Power Operations (INPO).

NERC NERC has established a program to audit the readiness of all reliability coordinators and control areas in North America to perform their assigned reliability responsibilities. These audits will give immediate attention to deficiencies in control area and reliability coordinator capabilities identified by the August 14, 2003, blackout investigation. The purpose of the NERC readiness audit is to provide an independent review of control area and reliability coordinator operations to identify areas for improvement and help them achieve excellence from a reliability operations standpoint. The NERC readiness audits initiate a process to ensure that operators of the bulk electric system have the tools, processes, and procedures in place for reliable operation. The NERC readiness audits will help control areas and reliability coordinators recognize and assess their reliability responsibilities and evaluate how their operation supports those responsibilities. NERC intends to use the results of these audits to help champion the changes required to better meet the reliability responsibilities of these entities. The NERC readiness audits will be 9

conducted on a three-year cycle; 64 readiness audits were completed by the end of 2004. Approximately, 60 audits are planned for 2005. The NRC staff has reviewed 20 NERC readiness audits and believes that effective actions are being taken to enhance the availability of offsite power for safe nuclear power plant operation.

In order to prevent and mitigate the impacts of future cascading blackout, NERC requires each regional reliability council to report to NERC quarterly on all violations of NERC and regional reliability council standards.

NERC revised its reliability standards and they were approved by its Board of Trustees on February 8, 2005. The new reliability standards took effect on April 1, 2005.

NERC is laying the groundwork for a system operator training program. The NERC training standards currently is posted on the NERC webpage for comment and sets forth educational requirements for all system operators. The training standards will drive the training programs that NERC will ultimately accredit and require system operators to successfully complete. The individual training programs will then be accredited based on how closely they follow the standards.

NERC approved the extension of the Urgent Action Cyber Security Standard. A permanent Cyber Security Standard is under development by NERC.

In addition, NERC issued its 2004 Long-Term Reliability Assessment in September 2004. According to the NERC report, resource adequacy is expected to be satisfactory throughout North America, provided new generating facilities are constructed as anticipated and NERC reliability rules are followed.

NERC sponsored workshops in April 2005 regarding the implementation of the new reliability standards for electric reliability coordinators, balancing authorities, transmission operators, planning authorities, transmission planners, and compliance mangers.

FERC On April 19, 2004, the FERC Commission issued a policy statement that, among other things, explained that the FERC Commission interpreted the term "Good Utility Practice" as that term used in the pro forma open access transmission tariff (OATT) to include compliance with reliability standards developed by NERC (Policy Statement on Matters Related to Bulk Power System Reliability, 107 FERC 61,052 (Policy Statement), clarified 108 FERC 61,288 (2004)).

On September 7, 2004, FERC sent "Utility Vegetation Management and Bulk Electric Reliability Report from the Federal Energy Regulatory Commission" to Congress.

FERC issued an Order requiring a response to a survey on operator training practices by control area operators and transmission providers on December 27, 2004.

On February 4, 2005, FERC issued a report titled, "Principles for Efficient and Reliable Reactive Power Supply and Consumption." FERC held a technical conference at its headquarters to discuss this report on March 8, 2005. The goal of the technical conference was to discuss the proper regulatory policy toward reactive power supply and consumption. Both technical and economic issues were discussed. Industry experts presented their views on reactive power supply in three panels. Panel 1 was reliability and technical issues; Panel 2 was the short-term reactive power issues; and Panel 3 was the prospective reactive power solutions. The FERC Commissioners will take the industry expert views into account as it considers the proper regulatory policy toward reactive power supply and consumption. The NRC staff is interested in this issue, because the reactive power is important to the reliability of offsite power to the Nation's nuclear power plants. With a weakened electrical transmission system, loss of the nuclear power plant generating unit could potentially result in a drop in voltage of the offsite power system to a value that would make it inadequate to supply the onsite safety-related loads. The NRC staff will follow this issue as it progresses.

10

The NERC Board of Trustees approved Version 0 Reliability Standards, to become effective April 1, 2005, which have the goal of restating exiting standards in a manner that is unambiguous and measurable on February 8, 2005. In an order dated February 9, 2005, the FERC Commission supplemented its reliability policy by making clear that the term Good Utility Practice as used in the OATT includes compliance with NERC's Version 0 Reliability Standards.

DHS The staff met with the DHS and FERC on March 1, 2005. The purpose of the meeting was to discuss with DHS and FERC areas of mutual interest regarding grid reliability. We discussed the electricity and nuclear critical infrastructure, graphic interface modeling of the health of the grid, an Acknowledgment and Agreement form for the NRC/FERC MOA, the benefits of the three agencies (DHS, FERC, and NRC) working together, and cyber security. The meeting summary is contained in ADAMS Accession No. ML050690243.

NEI On October 20, 2004, the NEI Grid Reliability Task Force submitted to NERC a Standard Authorization Request (SAR) for a proposed reliability standard regarding nuclear offsite supply reliability. The first posting of the SAR has been completed and all comments were received by January 7, 2005. A drafting team is being formed by NERC to draft the proposed standard.

The staff participated in the Grid Reliability workshop in Atlanta on February 16-17, 2005, sponsored by NEI, INPO, EPRI, and NERC. The main theme of the meeting was the importance of communication between the nuclear power plant operator and the grid operator. The NRC Deputy Executive Director for Reactor Programs made a presentation regarding the NRC perspective regarding grid reliability. The purpose of the workshop was to make the industry aware of grid reliability issues and share information regarding emerging good practices. The audience consisted of nuclear plant operators, transmission system operators, independent system operators, contractors, consultants, NEI, INPO, Electric Power Research Institute (EPRI), NERC, and NRC. The workshop consisted of presentations and breakout sessions. The presentations were informational and the breakout sessions were discussion-based. The breakout sessions allowed participants to ask questions and to learn best practices from their peers. In addition, the workshop focused on new NERC reliability standards, improvements in operational planning, and communication issues as well as raising awareness to nuclear power plant offsite power requirements. INPO presented information concerning SOER 99-1 analysis of grid related operating experience, and switchyard/substation improvements. The meeting summary is contained in ADAMS Accession No. ML050610414.

INPO On December 9, 2004, INPO issued World Association of Nuclear Operators (WANO) Significant Operating Experience Report (SOER) 99-1, 'Loss of Grid - Addendum." The Addendum to WANO SOER 99-1 included the lessons learned from loss-of-grid and other events experienced by WANO members since 1999. The lessons learned were (1) more formal agreements between the nuclear plants and the grid operators are needed to improve grid reliability and ensure timely restoration of off-site power, (2) procedure guidance is sometimes insufficient to verify that the appropriate grid voltage is being maintained, and (3) grid and switchyard electrical equipment that can affect plant operation needs to be effectively maintained to ensure off-site power is reliable.

The staff met with INPO in Atlanta on February 15, 2005. The purpose of the meeting was to discuss with INPO areas of mutual interest in accordance with the Memorandum of Agreement (MOA) signed December 24,1996 (ADAMS Accession No. ML011770437). The meeting discussed INPO activities, NRC activities, SOER 99-1, and a process to exchange information under the MOA. INPO also provided a tour of its facility. The meeting summary is contained in ADAMS Accession No. ML050590120.

11

NRR Technical Contacts: Amritpal Gill, DEIEEIB, Station Blackout Review Topical Area, 415-3316 George Morris, DEIEEIB, Offsite Power System Availability Topical Area and Risk Insights Topical Area, 415-4074 Thomas Koshy, DE/EEIB, Interactions with Stakeholders Topical Area, 415-1176 Martin Stutzke, DSSA/SPSB, Risk, 415-4105 NRR Lead PM: Kimberley Corp, DE/EEIB, 415-1091 RES

Contact:

Dale Rasmuson, RES/DRAA, 415-7571 Bill Raughley, RES/DSARE, 415-7577 12

DAVIS-BESSE LESSONS LEARNED TASK FORCE RECOMMENDATIONS REGARDING ASSESSMENT OF BARRIER INTEGRITY REQUIREMENTS (FINAL UPDATE)

Last Update: 06/30/05 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 1: 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 NRRIDE NRR/DSSA

b. Assess adequacy of licensee 05/05 (C) NRR/DIPM Regions procedure requirements based on results of inspections.

3. Develop inspection guidance pertaining to 1/05 (C) NRRIDIPM RES/DET RCS unidentified leakage that includes ML050270190 NRR/DE action levels to trigger increasing levels of NRR/DSSA NRC interaction with licensees in response to increasing levels of unidentified RCS leakage_LLTF 3.2.1 (2):Highl 13

Milestone Date Lead Support (T=Target)

(C=Complete)

4. Evaluate RCS leakage requirements and leakage detection systems.

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 (3) Issue final report as NUREG/CR 12104 (C) RES NRR

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 (C) 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 and 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.

14

Milestone Date Lead Support (T=Target)

(C=Complete)

d. Prepare a memorandum from division 03/05 (C) NRR/RES directors to office management to ML050830139 disposition conclusions in staff white paper.

e. Implement approved changes in RCS and Not Required RCPB leakage requirements using ML050830139 appropriate regulatory tools.

[3.2.1 (1):High]

Part II. Performance Indicators (PI)

1. Continue ongoing efforts to review and 5/05 (C) NRR/DIPM RES/DRAA improve the usefulness of the barrier integrity ML051440371 RESIDET 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 IlIl. 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 (C) RES/NRR address: ML050590324 ML050590328

- 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 05/05 (C) RES/NRR directors to office management to disposition ML051380060 conclusions in staff white paper.

15

==

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 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.

16

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 "[t]he reactor coolant pressure boundary shall be designed, fabricated, erected, and tested so as to have an extremely low probability of abnormal leakage."

• 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."

17

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 I, 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 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 71 111.08.

18

These revisions were issued in May 2004. The assessment of the adequacy of licensee procedure requirements was completed as part of the 2005 annual ROP self assessment process. The staff's review of inspection results and feedback from each Region regarding the implementation of these changes indicates that the licensees' alarm response procedures and operating procedures provide adequate guidance for the identification and corrective actions for reactor coolant system boundary leakage. No implementation issues or findings were identified in this area.

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.

Additional technical guidance, including a tool to determine statistically if a trend exists, was issued in January 2005.

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 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.

19

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 NUREG/CR-6861, "Barrier Integrity Research Program: Final Report" (ML043580207) in December 2004.

A working group consisting of members from the Materials Engineering Branch in RES and the Plant Systems Branch and the Materials and Chemical Engineering Branch in NRR was formed to further evaluate the DBLLTF recommendations and NUREG/CR-6861. In evaluating the need for additional requirements pertaining to leakage detection, the staff considered past operating experience related to reactor coolant system integrity and the performance deficiencies that led to the degradation that occurred at Davis-Besse. The staff identified techniques that could improve localized leak detection and on-line monitoring and several areas of possible improvements to leakage detection requirements that could provide increased confidence that plants are not operated at power with reactor coolant pressure boundary leakage. However, implementing these increased capabilities would be expected to produce a very modest reduction in loss of coolant accident frequencies. As a result, it was the staff's judgment that the associated risk reduction that could be realized would not justify the costs to install and maintain such equipment (i.e., the cost-benefit criteria associated with implementation of the backfit rule (10 CFR 50.109) could not be satisfied). Item 1.4.e is not required since no changes were recommended for currently operating facilities.

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.

The PI program is a voluntary program for the industry in that there are no regulatory requirements associated with the program. Changes to the program generally require consensus between the NRC staff and industry. To assess the feasibility of DBLLTF recommendation 3.3.3.3, the industry and NRC staff established a subgroup composed of three NRC staff and three industry representatives. In its discussions, the subgroup concluded that at present it is not feasible to track the number, duration, and rate of primary system leaks that have been identified but not corrected. This is due, in part, to the difficulty licensees have in determining small leak rates accurately, and, in part, to the quarterly data reporting, which makes it difficult for the staff to determine the number of leaks, the rate, and the duration.

However, the staff will continue to follow progress in leak detection capability and industry efforts in this area.

The existing RCS Leakage PI already monitors identified leakage. The intent of the PI is to call attention to those plants that have identified primary system leaks but have not corrected them in a timely manner.

As part of the effort to continue to improve usefulness of the barrier integrity Pis and the Reactor Oversight Process, the stafffindustry working group agreed to have the subgroup explore possible improvements to the RCS leakage PI. The subgroup has met on a number of occasions and is currently interacting with the Westinghouse Owners Group to understand the efforts being undertaken by that group.

In summary, the staff assessed the feasibility of establishing the PI which tracks the number, duration, and rate of primary system leaks that have been identified but not corrected and determined that it is not feasible at this time. As part of the ongoing efforts to improve the Reactor Oversight Process and PI Program, the staff is working with its external stakeholders and has established a NRC staff/industry subgroup to explore and possibly improve the RCS Leakage PI.

Part IlIl milestones were added to track completion of LLTF 3.3.7(3). A working group consisting of RES and NRR staff was formed to study the risk assessment methods related to passive component degradation, evaluate their adequacy, and write a white paper on this issue. The white paper was completed in March 2005. Recommendations were forwarded to management by May 2005. The WG report found that the available risk assessment models alone are usually inadequate to provide strong 20

support for many types of decisions. The portions of the risk models that predict degradation rates and structural integrity effects, and the limited information about plant-specific conditions often make it difficult to make reliable predictions very far beyond the latest available measurements. However, the WG concluded that decisions made on the basis of a proper combination of inspection results and predictive modeling can be successfully used to adequately control the risk to the public. The steam generator tube integrity program that has recently been developed in cooperation with industry, is suggested as a model for success in other portions of the pressure boundary components that are important to safety.

The Division Directors agreed that the methods used to assess risk are adequate and data limitations need to be well understood. An understanding of the limitations and uncertainties is necessary to make the appropriate decision. Degradation issues are not unique with respect to the need for decision-makers to carefully consider the degree of uncertainty of and the level of confidence in the available information and analytical results. But, it is more difficult than usual to do so for degradation issues, because of the greater reliance on predictive models in place of empirical reliability data. Therefore, based on the WG findings, the evaluation required by DBLLTF 3.3.7(3) is complete.

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 NRRIDIPM Lead

Contact:

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

Contact:

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

Contact:

William Bateman, DE, 415-2795

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.

21

SIGNIFICANCE DETERMINATION PROCESS (SDP) IMPROVEMENT TAC Nos. MA9164, MB0046, & MB2203 Last Update: 06/30/05 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 Date Stlaus

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.

Proposed change to IMC 0609 incorporates requirements for the early stage of the assessment period to convene a pre-SERP to establish scope and schedule for risk-informing complex and potentially safety significant findings.

22

Task °Dat jl Led'dl lStatus ]

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.

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 10/1/03 (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 "ROP 12/30/03 (C) IIPB IMC0307, ROP Self Self-Assessment Assessment, Section Program" to improve 06.01 b6, Timeliness of evaluation of inspection Identification, addresses the effectiveness in timely issue.

identification of performance deficiencies. [OIG - 5]

Objective 1.8 Change IMC 0307 "ROP 04/30/06 (T) IIPB Findings presented to the Self-Assessment SERP and tracked for timely Program" SDP issuance of the final risk-timeliness metrics to informed determination better reflect the time represents one half of one spent on findings percent of all findings issued presented to the SERP. by the ROP. To better represent the time spent on this small but important group the existing metric will be augmented by establishing an average age limit for findings in this category.

23

Task ICompletion' lilad Dat l

-s St-u

2. Improve SDP Process Objective 2.1 Revise Attachment 1 of Complete IIPB IMC 0609 Att. 1 was 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.()

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.

24

l-Task J_-Cl-leio-jLead - status 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:12 ) 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. SOP 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 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 ROP 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). I I 25

Task Il om LeadStatu

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.(2) 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. l

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) 26

l.-- TkI-j-Co tion I ask  :-j:1mpel -> 'Lead_. Status Objective 2.6 Develop a plan for long Complete The SDP Improvement range improvements to Initiative Task Action Plan is the SDP.13) [OIG-1] NRR's tool for tracking SDP improvement activities.

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.

uconstruction 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) 11131 27

l:--9Task-l° Dw a tetn a ltus *

. ,:, . : .t

a. Develop tools and simplify the TBD (Multi- I SPSB Draft report based on the process of accounting for year effort) pilot is under evaluation.

external initiators in phase 2 of Parallel options under the SDP. 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. Draft pilot report issued November 2004, proposed 3 phase development. 1) Green Screen, a flow chart attached to IMC 0609, to help the inspectors determine whether external events contribution needs to be considered for green findings. Tentative schedule for the end of 2005.

2) Develop external event worksheets to be attached to the phase 2 worksheet of the risk-informed inspection notebooks. Tentative schedule for the end of 2006. 3) Update the existing SPAR models to incorporate external events. Schedule TBD.

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 IlIl.

28

Tas- Completion Lead Status

c. Standardize benchmarked 12/31/05 (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 12/31/05 (T) SPSB/ Supplemental training needs issue revised guidance for the IIPB will be evaluated prior to use of the pre-solved risk tables. issuance of the pre-solved risk tables. The usage rules associated wit the risk-informed notebooks have not changed therefore, no additional training for the use of the notebooks is needed beyond the training that is routinely provided by the SRAs to the inspectors.

The pre-solved tables are spreadsheets and their use and relationship to the notebooks is self-explanatory. However, a website based tutorial is being considered which will provide generic examples using a typical spreadsheet.

29

l :Task Ts.'P ' - t " -lid Lead l - Status 'l 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 1 to 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 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 Based on the late 2005 3.6.3(2)] issue date for Revision 2 of the notebooks no routine maintenance to update the documents should be necessary. Adjustments recommended by the users should be made using the existing feedback process.

Objective 3.3 Develop or improve existing SDP tools as applicable in the following areas: [OIG-3] I 30

F- ;  : -1Task x[-i: , ',l,Comp'letion, Lead  ; S'atu '

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 05/19/05 (C) IIPB

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 Storage 06/30/06 (T) IIPB This procedure is in development.

Objective 3.4 Improve the physical 06/30/06 (T) NSIR The staff is considering an protection SDP, if industry (NEI) request to necessary, accounting Support: conduct another pilot, using for any safeguards IIPB the SDP in parallel with a policy changes. SDP proposed by NEI. The pilot will start in the second quarter of 2005. Six month pilot using the NEI recommended SDP started 6/11/05.

31

Task

• I l °pionl - Lead i Status 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/sal spsb/webpages/srapal ge/phase3_serps/rop-case-status.html Objective 3.6 Consider development 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.1 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) NRRISPSB 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.

b. Develop criteria and to allow the 04130/05 (T) RES The RASP will evaluate the staff to recognize situations Support: possibility for developing where "the state of knowledge" SPSBI 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 isof 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 32

l Task Ie Co letion l -Status

-lLead:

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 licensee's risk analyses.

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 )

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

IMC 0609A revision.

33

Datel! d- l Le.Task Status-

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

inspector counterpart meetings:

[OIG-3]

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 6130/02 (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.

34

T kj c Da-teo d l , Status

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 in guidance on the order to meet the timeliness termination of ongoing guidelines, the termination risk evaluations when it of ongoing refinement of risk is clear that such activity evaluations should be based will result in exceeding on management timeliness guidelines. 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 is detailed in a SECY paper, ROP Self Assessment for 2004. Also see section titled "Potential Problems" at the end of this document. IMC 0609, Significance Determination Process, is being updated to incorporate new guidance which will allow a pre-SERP panel to extend the SDP completion requirement beyond 90 days based on the complexity and potential high safe significance of the finding, and decide on the scope of the evaluation for reactor safety issues. SDP metrics will also augmented to provide a more realistic status of the SDP timeliness and quality.

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]

35

'TaskDt Cmpletio* 1ISau Leadtau

.. Dat Objective 5.3 Revise the ROP TBD 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 Internal stakeholder input is determine an being solicited in this area to appropriate color to help develop appropriate associate with findings guidance. The date for where the uncertainty in finalizing the process will be the risk evaluation determined after receiving arising from the input from the regional characterization of the offices.

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)]

36

l- -Task :- l Daete L- d; l: Sttus-

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 M01 0720A 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.

37

==

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-99-007, the staff concluded that adequate assurance of licensee performance would be achieved through the use of risk-informed performance indicators (Pls) 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 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.

38

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-15) 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. In a memorandum dated February 23, 2005, the OIG accepted the staff January 26, 2005, responses to the remaining recommendation and declared all recommendations closed.

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.

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.

39

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 40

STEAM GENERATORS TAC Nos. Description Last Update: 07/06/05 M88885 Steam Generator (SG) Integrity Rulemaking Lead Division: DLPM M99432 GL: SG Tube Integrity Supporting Divisions: DE, DIPM, DSSA MA4265 NEI 97-06 Supporting Office: RES MA5037 SG Action Plan MA5260 DPO on SG Issues MA7147 GSI-163 MA9881 Regulatory Issue Summary - IP2 SG Tube Failure MB0258 SG Action Plan Administration MB0553 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 MC4330 SG Technical Specification Generic Review - ACRS Interface Item No. Milestone Date Lead Support (TAC No.)

(T=Target)

(C=Complete) 1.17 Publish Notice of Availability of TSTF 05/06/05 (C) DRIP in FR (NEI 97-06) N. Salgado 1.21 Staff issues a Generic Letter TBD (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 41

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.

42

Item No. Milestone Date Lead Support (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.

43

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

(r=Target)

(C=Complete) l 3.1 I) 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 DSSA DE 3.1a through 3.1j to evaluate the TBD (T) S. Long E. Murphy conditional probabilities of multiple Note 14 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 09/30/05 (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) 44

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 04/01/04 (C) RES DSSA and 3.4.b.1, perform additional ML040910022 C. Boyd W. Jensen analysis to: include modeling of heat (Non-public) transfer enhancement from radiation 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 117 scale data to assess 08/31/02 (C) RES DSSA tube to tube temperature variations D. Bessett W. Jensen and estimate variations for plant S. Long scale.

d) Perform more rigorous uncertainty 03/31/06 (T) RES DSSA analyses with system level code to Note 13 C. Boyd W. Jensen address the uncertainty caused by S. Long key governing parameters.

Distribution functions will be developed for key parameters. Peer review.

.5 .5 5. .5 45

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

(T=Target)

(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 01/25/05 (C) 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 C. Hammer the hot leg taking into account the DSSA material properties of the base metal, S. Long welds, and heat affected zones in the presence of residual and applied stresses, in addition to the pressure stress, and the presence of flaws.

46

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

(T=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 C. Hammer operability and "weakest link" DSSA considerations for these components. S. Long DE h.3) Conduct large scale tests if 11/30/05 (T) RES E. Murphy needed. J. Page C. Hammer DSSA S. Long I) Use existing international data and 05/28/04 (C) RES DSSA develop analyses for predicting leak ML042720174 J. Muscara S. Long rates of degraded tubes in restricted 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 TBD (T) DSSA DE tasks 3.4a through 3.4j and 3.5 to Note 19 S. Long E. Murphy address ACRS criticisms of risk RES assessments for ARCs that go J. Muscara beyond the scope and criteria of C. Boyd GL 95-05 (e.g., ARCs that credit H. Woods "indications restricted against burst")

as well as dealing with other SG tube integrity and licensing issues (e.g.,

relaxation of SG tube inspection requirements).

47

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

(TCTarget)

(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) RES DSSA methods and appropriate treatment of ML031810770 H Woods S. Long uncertainty for identifying severe 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) See Note 16 RES DSSA logic framework, identify scenarios, H. Woods S. Long calculate the frequency of containment bypass events at an example plant, make indicated method improvements, and document the improved methods and results.

48

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 M. Junge 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 M. Junge 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 M. Junge 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) 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 49

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

(T=Target)

(C=Complete) 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 Register for 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.

3.10 To address concerns in the ACRS (MB7216) 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) 50

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

(T=Target)

(C=Complete) 3.10 Specific tasks include:

(continued) 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.

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) . -

51

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. ML010780125).

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."

6. The thermal-hydraulic analyses (items 3.1a through 3.1c) will provide input into the tube integrity analyses (items 3.1 d through 3.1 j) 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 ongoing. A schedule will be developed once screening is completed.

12. A draft version of the generic letter (GL 2004-xx, Steam Generator Tube Integrity and Associated Technical Specifications) was issued for a 60 day comment period in the Federal Register (FR) in October 2004, and public comments have been received. This GL will request 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 52

version of the TS will not be required to respond to the GL. One of the comments is that the staff should wait to issue the Generic Letter until some time period after TSTF-449 has been approved for use. The staff is evaluating the comment to allow licensees more time to submit a TS amendment in response to the TSTF approved for use and published in the FR on 5/6/05.

13. March 31, 2006, is the currently estimated target date for milestone 3.4.d. Although milestone 3.4.f has been 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. Task completion is delayed due to assignment of staff to higher priority work on PTS.

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. The NRR and RES staff are currently reviewing the results of the work completed under 3.5(d).

Discussions are underway to decide future actions needed to complete items 3.5(d) thru (g).

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. The results of the PRA work described in 3.5.d and approval by RES management of the details associated with completing this work scope, will help identify the level of effort needed to complete this work and the associated schedules.

19. The task is dependent on completion of preceding 3.4 subtasks and all 3.5 subtasks. New completion dates need to be developed based on scheduled completion of 3.4 and 3.5 milestones.

==

Description:==

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-163 (Multiple Steam Generator Tube Leakage); 3) the NRC's Indian Point 2 (IP2) 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 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 53

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-Leamed 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).

- 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 Thermal/Hydraulics, and the Full Committee on SG DPO related action items.

54

- 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) 55

DAVIS-BESSE LESSONS LEARNED TASK FORCE RECOMMENDATIONS REGARDING STRESS CORROSION CRACKING TAC No. Description MB2916 Non plant-specific activities for Last Update: 06/30/05 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 03/04 (C) RES/DET DE available worldwide on Alloy 600, Alloy ML040920026 690 and other 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 07/03 (C) RES/DET DE with respect to their continuing use in the ML032461221 susceptibility index.

[LLTF 3.1.4(1)-Medium] . -

56

Milestone Date Lead Support (T=Target)

(C=Complete)

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

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

4. Incorporate Order EA-03-009 Note (2) requirements 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 06/05 (C) DE RES/DET efforts to develop revised RPV Head Note (1) DSSA inspection requirements (ASME Code RegionsSection XI). 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 TBD DE RES/DET Code 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 (C) RES/DET DE findings from Part I, Items 1 and 2, and NUREG-1823 Part II, Item 1. ML050690012 57

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 ML043000274 corrosion 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 06/03 (C) DE DLPM regulatory actions and determine ML031760568 DRIP appropriate regulatory tool(s). DIPM DSSA Regions

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

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

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.

58

Milestone Date Lead Support (T=Target)

(C=Complete)

8. Review and evaluate the adequacy of 12/05 (T) DE RES/DET revised ASME Code Requirements for Note (1)

Pressure Testing/Leakage Evaluation being developed by the ASME Code, Section Xl, 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] l

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

[LLTF3.3.2(1)-High]

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

High]

DE

b. Perform follow-up evaluation of 05/05 (C) DIPM RES/DET inspection guidance and licensee ML051360392 Regions program acceptability after conducting 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.

==

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 59

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.

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 (T1-152) 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.

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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.

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.

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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 (ML032461221).

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 (ML040910354).

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). The staff participated in ASME Code Committee development of revised inspection requirements. In June 2005, the ASME Board on Nuclear Codes and Standards approved Code Case -729, which provides additional inspection requirements for RPV upper heads. Therefore, Part I, item 5 is considered complete. Once Code Case -729 is formally published, the staff will evaluate endorsing it in a revision to 10 CFR 50.55a.

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 (ML032100653). The evaluation of responses to Bulletin 2002-01, which included audits of BACC programs at five plants, determined that the plants complied with requirements at the programmatic level. In general, the results indicated weaknesses in the licensees' BACC and ASME Section Xl programs. The weaknesses identified in the RIS included identifying pressure boundary leakage and potential leakage paths, looking for boric acid crystals, walking down systems when the plant is entering or leaving the hot shutdown mode, and detecting small leaks during normal power operation. 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 (ML043000274). This information and the information previously collected on nozzle cracking along with the staff evaluation of the SCC models have been incorporated into NUREG-1823, "U.S. Plant Experience with Alloy 600 Cracking and Boric Acid Corrosion of Light-Water Reactor Pressure Vessel Materials" (ML050690012). The staff also contracted Argonne National Lab to conduct a test program on boric acid corrosion of light-water reactor pressure vessel materials. The results will be published in NUREG/CR-6875.

The staff is 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 to develop a course of action and an implementation schedule to address LLTF 3.1.1 (1). The staff met with industry representatives on March 24, 2005, to discuss their activities for addressing PWSCC in nickel based alloy butt welds and in other locations in the reactor coolant system. The presentations were high level and lacked the technical details and schedular commitments the staff were expecting. Based on the results of these meetings and interactions with NRR senior management in meetings in March and April 2005, the staff is developing a regulatory action package to address the need for an ongoing program of inspections, which will also address the course of actions associated with the closure of DBLLTFR 3.1.1(1). The staff expects to complete the development of this regulatory action by early fall 2005.

In Part III activities, inspection procedure revisions addressing RPV head inspection and boric acid corrosion control programs were issued. Temporary Instruction (TI) 2515/150, issued on October 18, 2002, provides guidance for assessing the licensees' RPV head inspections pursuant to Order EA-03-009.

The TI also includes instructions for follow-up on findings of boric acid accumulation. Inspection Procedure (IP) 71111.08, "Inservice Inspection Activities," dated May 14, 2004, provides periodic inspection requirements and guidance for boric acid corrosion control. The Regions provided feedback regarding the implementation of TI 2515/150 and IP 71111.08 since October 2002. In addition, the Inspection Program Branch (IIPB) reviewed inspection results from TI 2515/150 and IP 71111.08. As a result of the licensees' visual and non-visual inspections and NRC direct observations and oversight of licensees' activities, a number of facilities have made repairs to their vessel heads and some have replaced the vessel heads. In some cases, repairs were required; in others the licensee took actions voluntarily. Feedback from each 62

Region and IIPB staff review indicates that the licensees' programs are generally adequate for locating and evaluating and/or correcting boric acid leaks. Although several inspection findings were identified, none were of greater than very low significance. The staff will continue to evaluate the effectiveness of this IP as part of annual ROP self-assessment and make appropriate improvements as needed.

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

Contact:

Stuart Richards, IIPB, 415-1257

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.

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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 71 111.08, 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 71 11.08 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.

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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.

66

PWR SUMP PERFORMANCE TAC Nos. MA6454, MA2452, MA4014, MA0704, M95473, Last Update: 07/08/05 MA6204, MA0698, MB4047, MB6411, MB3103, MB8052, Lead NRR Division: DSSA MB7776, MB9470, MB4864, MB9931, MC0307, MC1154, Supporting Divisions: DE, MB9549, MC4272, MC5881, MC6467, MC6470 DRIP, DLPM, and DET (RES)

MB5625, MB4865, MC0725/6, MB5221, MB5964, GSI: 191 MB6589, MB7228, MC1627, MB5334, MC2628, MB6946 MC6659, MC6661, MC6730, MC6731 MILESTONES DATE (T/C)

PART l: BWR ECCS SUCTION STRAINER CLOGGING ISSUE

1. NRCB 96-03, "Potential Plugging of Emergency Core Cooling Suction 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) o Chemical effects: Determine if sump pool environment generates 04/06 (T) by-products which contribute to sump clogging o Debris Transport & Head loss: Confirmatory research on debris 04/06 (T) transport of coatings and head losses associated with PWR containment materials with and without chemical effects o Downstream effects: Confirmatory research on the effect of 04/06 (T) injected debris on HPSI throttle valve performance 67

MILESTONES DATE (T/C)

MILESTONES DATE (TIC)

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) 02102 (C) o Public meeting with NEI, WOG, B&WOG, CEOG 03/02 (C) o ACRS Briefing on proposed draft GL 02103 (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 12104 (C) o NRC starts Reviews of GL Responses and Selective Audits 09/05 (T) o GL date for licensees to start modifications, if needed, using 04/06 (T) approved guidelines o NRC closes GSI-191 12107 (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-1 91, "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 formed 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-1 91 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 due to insulation debris were discussed in GL 85-22, NPotential for Loss of Post-LOCA Recirculation Capability due to Insulation Debris Blockage," dated December 3,1985. This generic letter documented 68

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 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 69

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.

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

http://www.nrc.cov/reactors/operatinpfops-experience/Dwr-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 minimize duplication of effort and to ensure effective utilization 70

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

Another example of margin is that in many cases, 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. 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-191 study, NRC'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 71

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 stakeholders including PWR licensees and the NEI sump performance task force on the progress toward resolving GSI-191. On June 30, 2005, the NRC held a public meeting with the Nuclear Energy Institute (NEI) and other stakeholders to discuss chemical effects, staff expectations in regards to the responses to Generic Letter (GL) 2004-02, and also informed licensees of expectations regarding containment coatings qualifications programs.

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 completing the review of 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, 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 held 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. The initial 90-day responses have been received from all PWR licensee's and are being reviewed by the staff. A pilot program to audit the implementation of the generic letter has been initiated. The first audit of Crystal River Unit 3 was completed in June 2005, with several additional pilot audits under consideration.

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 72

NRR Technical Contacts: Ralph Architzel, SPLB, 415-2804 Tom Hafera, SPLB, 415-4097 Hanry Wagage, SPLB, 415-1840 Shanlai 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)

Ruth Reyes, SPLB, 415-3249 (Upstream)

RES Technical Contacts: B. P. Jain, ERAB, 415-6303 Rob Tregoning, ERAB, 415-6657

References:

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, NUnexpected 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.

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.

73

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 04-07, PWR Sump Performance Evaluation Methodology, December 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.

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, "Pressurized Water Reactor Containment Sump Evaluation Methodology,"

dated December 6, 2004.

Report on Results of Staff Pilot Audit - Crystal River Analyses Required for the Response to Generic Letter 2004-02 and GSI-191 Resolution, dated June 29, 2005.

74

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: 06/30/05 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, rulemaking, 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)

18. Public Meeting. 06/18/03 (C) 75

MILESTONES DATE (T/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 07/29/04 (C) rulemaking, 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 input on voluntary initiatives for backup 09/21/04 (C) power supply to the 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 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 consensus 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 licensee initiatives for providing backup power sources to the hydrogen igniters.

33. The NRC staff met with senior representatives of the six affected PWR and 03/30/05 (C)

BWR licensees to discuss safety-security-related insights and briefed the industry regarding potential changes to the voluntary actions.

34. A memorandum to the Commissioners from the EDO was issued to inform 06/14/05 (C) the Commission of the regulatory analysis results and staff's plans for resolution of GSI-189.

==

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-189, NRR recommended the addition of a backup power supply for the combustible gas igniters for the plants with Ice Condenser or Mark IlIl 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).m There are 13 susceptible plants involved. The affected plants are the four dual-unit PWR nuclear stations with ice 76

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-00-1 98, a 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 IlIl 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, 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 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 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 early containment failure probability is dominated by non-DCH hydrogen combustion events for ice condenser containments due to relatively low containment free volume and low containment structural strength in these designs. These containments rely upon pressure-suppression 77

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 concentration 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 containments are also pressure-suppression designs, but are operated with the containment inerted," i.e., the drywell and air space above the suppression pool are flooded with nitrogen gas and 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 IlIl 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 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 they did not think the use of SAMGs to be 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 the 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 Owner's Group (BWROG) prior to making a decision to pursue rulemaking. NRR staff also discussed alternatives with the BWROG for the four affected BWR plants.

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Proposed Actions: To resolve GSI-189, DSSAISPLB 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 NRC does not have a strong basis for pursuing rulemaking. This is because (1) GSI-189 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 safety benefit of enhancement that only improve consequence mitigation capability. Adding backup power to hydrogen igniters improve defense-in-depth, but would not be easily defensible through the rulemaking process. Therefore, NRR staff is pursuing voluntary license initiatives as an alternative to rulemaking. In addition, DRIP/RPRP is completing the cost-benefit analysis to determine whether the cost for implementation is justifiable for the safety enhancement.

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 lIl 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 a willingness to provide new design for the backup power supply as the standard emergency power on the 69Kv board. These utilities have promised to provide their proposals for the NRC staff review. Currently, NRR has generally completed the design criteria with no major changes, and the contractor, ICF, completed the draft regulatory analysis in December 2004.

However, the BWR licensees, BWROG representatives, stated that 1-hour time limit is insufficient for the BWR Mark lIl containment to connect 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 lIl 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-189 and (2) 1-hour versus 2-hour time limits for the BWRs to connect 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-1 89 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 SPSB and RPRP, briefed the ET/LT in a meeting dated November 29, 2004, on plans to resolve GSI-1 89. 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.

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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 III Containment Designs," August 15, 2001, (ADAMS #ML012330522).

SECY 00-1 98, '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.

Backfit Rule - NRR technical staff believed that adding backup power can provide 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 DRIP/RPRP staff finalized the regulatory analysis. The final regulatory analysis indicated that the backup power modification may provide a substantial safety benefit at a justifiable cost for the PWRs with ice-condenser containment, and the proposed voluntary actions provide the majority of the benefit. The costs exceed the benefits for all BWR regulatory options, and none of the options for the BWRs provides a substantial increase in the overall protection of public health and safety. However, defense-in-depth considerations in improving the balance among accident prevention and mitigation provide an additional un-quantified benefit for both containment types. On June 14, 2005, the EDO issued a memorandum to inform the Commission of the regulatory analysis results and staff's plans to pursue voluntary actions for resolution of GSI-1 89.

In February and early March 2005, the NRR staff met with representatives of RES, NSIR, and OEDO to develop and understanding of the safety security interface and actions initiated in the security arena that bear on the solution of the safety issue. On March 30, 2005, the NRC staff met with senior representatives of the six affected PWR and BWR licensees to discuss safety-security-related insights for consideration in developing plans for voluntary actions. The staff will continue monitoring the safety-security interface and will inform the licensees of new insights related to GSI-1 89.

Contacts:

NRR Lead Project Manager: L. Mark Padovan, DLPM/LPD 3-1, 415-1423 NRR Lead Technical Reviewer: Jin-Sien Guo, DSSA/SPLB, 415-1816 NRR Technical

Contact:

Bob Palla, DSSA/SPSB, 415-1095 NRR Rulemaking

Contact:

Stewart Schneider, DRIP/RPRP, 415-4123 RES Technical

Contact:

Allen Notafrancesco, DSARE/SMS, 415-6499

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

80

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-1 150, "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-150 Data Base Assessment Program: A Description of the Computational Risk Integration and Conditional Evaluation Tool (CRIC-ET) Software and the NUREG-l150 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." ML003761979).

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 III 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 lIl (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 III Containments to Early Failure from Hydrogen Combustion During a Severe Accident."

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 0080), Proposed Rulemaking-Risk Informed 10CFR50.44, "Combustible Gas Control In Containment", (WITS 20010003).

23. Advisory Committee on Reactor Safeguards Meeting Minutes, 49 3 rd 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 III 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.

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26. Memorandum from Ashok Thadani, RES to William Travers, EDO, dated October 1, 2002, regarding, "Revision to NRC's Regulatory Analysis Guidelines [NUREG/BR-00581 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, 49 7 th 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 NRecommendations Proposed by the Office of NRR for Resolving Generic Safety Issue -189, Susceptibility of Ice Condenser and Mark IlIl 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 III 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 IlIl 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, NResolution 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."

35. Benefit Cost Analysis of Enhancing Combustible Gas Control Availability at Ice Condenser and Mark III 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 III 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).

38. Memorandum from Luis A. Reyes, EDO, to The Commissioners, dated June 14, 2005, "Status of Staff Activities to Resolve Generic Safety Issue 189, 'Susceptibility of Ice Condenser and Mark III Containments to Early Failure from Hydrogen Combustion During a Severe Accident' (WITS 20010144) (ML051440875).

39. Attachment to Memorandum from Luis A. Reyes, EDO, to The Commissioners, dated June 14, 2005, "Background - Status of Staff Activities to Resolve Generic Safety Issue 189, 'Susceptibility of Ice Condenser and Mark ill Containments to Early Failure from Hydrogen Combustion During a Severe Accident' (WITS 20010144) (ML051590380).

40. Regulatory Analysis for Proposed Action to Address Generic Safety Issue 189: Susceptibility of Ice Condenser and Mark IlIl Containments to Early Failure from Hydrogen Combustion During a Severe Accident, May 24, 2005 (ML051450060).

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CONTROL ROOM HABITABILITY TAC No. MC0021 Last Update: 06/30/05 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-1 115), 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-1111)

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-1111:

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 RlI: 07/16/02 (C)

RIII: 08/06/02 (C)

RIV: 07/18/02 (C)

Resolve public comments on draft Regulatory Guides DG-1 111, 12/30/03*

DG-1113, DG-1114, and DG-1115 Office review and concurrence of final Regulatory Guides and Generic DG-1 111, DG-1 113:

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) 83

MILESTONE DATE (T/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 1/24/05 (C)

Regulatory Guide 1.196 Develop response to TSTF letter of 3/8/04 Y24/05 (C)

Transmit staff proposal for revision to TSTF-448 Y24/05 (C)

Review 180 days responses to Generic Letter 90 days after receipt-Develop & transmit RAls on 180 days responses to licensees Conduct survey of 3-4 plants who filed 180 days responses to Generic 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.

Beginning 10/1/05 4-5 prepared per month until back log is retired.

• • • • Surveys to begin 3/15/06 and to be completed by 9/15/06.

==

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-1 9 84

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-19 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 reactor through 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-19 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 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.

85

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-1 9 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-1 4844 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 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, NControl 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 86

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.

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.

87

Regulatorv 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:

(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 June 24, 2005, the following plants have not provided final responses to the Generic Letter: Davis Besse, Ginna, Grand Gulf, Hatch, Indian Point Unit 3, Oyster Creek, Palisades, Perry, Pilgrim, VC Summer, and Susquehanna.

Approximately 88 percent of the reactors have now provided completed responses. 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 the technical specification in the Appendix. The staff's proposed revision was reflected in a September 30, 2004, amendment issued to the Farley Plant and in a January 24, 2005, letter to the Technical Specification Task Force (TSTF). The January letter was the staff's response to the TSTF's changes to TSTF-448, Control Room Habitability, proposed in the TSTF's March 8, 2004, letter to the staff. On May 26, 2005, the staff met with the TSTF and the NEI Task Force on Control Room Habitability to discuss the basis for the proposed technical specification in the January 24 letter. During the meeting the TSTF provided their comments regarding the proposed technical specification. As a result of the meeting, the TSTF will propose a revision to TSTF-448. This revision is scheduled to be submitted to the staff in July 2005.

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.

88

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/DSSANNRR, 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-1 465, 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-14844, 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.

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FIRE PROTECTION PROGRAM TAC Nos. M40015, MA1139, MA1752, MA4507, MA4720, Last Update: 06/30/05 MA4721, MA9013, MA9014, MA9015, MA9016, MB1311, Lead NRR Division: DSSA MB1313, MB2921, MB3203, MB6729, MB6932, MB7726, Supporting Divisions: DIPM, MC0514, MC2582, MC2584, MC2589, MC3184, MC3628, DRIP, and DRAA (RES)

MC3796, MC401 1, MC4395, MC5630, MC5660 Supporting Offices: OE, OGC MILESTONES DATE (T/C)

ITEM I: RISK-INFORMED PERFORMANCE-BASED RULE (NFPA 805)

1. Publish final rule 06/04 (C)

2. 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-1 139, & inspection concepts 10/04 (C)

6. Comment on draft fire PRA requantification report (NUREG/CR-6850) 11/04 (C)

7. Receive DG-1139 public comments 12/04 (C)

8. Commission grants enforcement discretion extension 01/05 (C)

9. Develop inspection template task force guidance 01/05 (C)

10. Issue draft pilot plant observation guidance in public mtg notice 01/05 (C)

11. Form task force to develop draft inspection input 04/05 (C)

12. Public meeting on DG-1 139, pilot plant reviews, NEI 04-02 02/05 (C)

13. RIC Fire Protection Session - Implementation Challenges 03/05 (C)

14. Incorporate public comments into final regulatory guide 04/05 (C)

15. Obtain DSSA approval on final RG for ACRS/CRGR Review 05/05 (C)

16. Send final regulatory guide to ACRS, CRGR, & OGC for review 05/05 (C)

17. Task force workshops to develop draft inspection template 04/05 (C)

18. ACRS meeting on final regulatory guide 05/05 (C)

19. CRGR meeting on final regulatory guide 05/05 (C)

20. Incorporate ACRS, CRGR, & OGC comments into final regulatory guide 07/05 (T)

21. Complete HQ & Regional draft inspection input review 07/05 (T)

22. Obtain final approval on regulatory guide and send for publication 10/05 (T)

23. Publish final regulatory guide endorsing NEI 04-02 11/05 (T) 90

MILESTONES DATE (TIC)

24. Review final fire PRA requantification (NUREG/CR-6850) prior to entry into 08/05 (T)

ADAMS

25. Received first licensee letter of intent to transition 02/05 (C)

(Three Duke Power NPPs)

26. Issue Transition Pilot Plant Plan 10/05 (T)

27. Review RES report on acceptable fire models 11/05 (T)

28. Incorporate inspection input 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 Regulatory Issue Summary (RIS) 2004-03, Revision 0 on circuit 03/04 (C) analysis

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 (C)

13. Issue RIS 2004-03, Revision 1 on circuit analysis 12/04 (C)

14. Issue draft RIS to provide clarification of regulatory requirement issues 05/05 (C) associated with post-fire safe-shutdown circuit analysis and protection - for 60-day public comment period

15. Receive and address comments on circuit issues/compliance 09/05 (T)

16. Issue final RIS on circuit issues/compliance 11/05 (T)

17. Prepare draft GL for management concurrence 06/05 (C)

18. Issue GL for public comment 08/05 (T)

19. Conduct public meeting on regulatory requirements RIS 08/05 (T)

20. Conduct public meeting on GL 10/05 (T) 91

MILESTONES DATE (T/C)

21. Issue final GL on circuit issues terminology [ TBD 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 interim 04/04 (C) 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)

8. Re-issue modified interim criteria for enforcement discretion to OE 09/04 (C)

9. Brief the ACRS fire protection Subcommittee and Full Committee 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 (RG) 02/05 (C)

13. Conduct public meeting to further solicit comments 04/05 (C)

14. Submit final rule to Commission/Complete 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 04/05 (C) o Meet with industry/licensees on Hemyc 04/05 (C) o Issue generic communication on Hemyc 04/05 (C) o Issue draft Generic Letter on Hemyc and MT 07/05 (T) o Review 3-hour M.T., fire performance test report 05/05 (C) o Conduct public meeting on Generic Letter 09/05 (T) o Issue final generic communication on Hemyc and M.T. 12/05 (T)

2. Epoxy coatings oReview NEI white paper 01/05 (C) 92

l MILESTONES I DATE (T o Develop response and have NRC Regional Offices review 04/05 (C) oIssue response to NEI white paper 08/05 (T)

3. RCP seal 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 06/05 (C) o Receive and review WOG input on seal performance 01/05 (C)

4. Manual lockout of automatic carbon dioxide fire suppression systems o Review NEI white paper 01/05 (C) o Develop response and have NRC Regional Offices review 04/05 (C) o Issue response to NEI white paper 07/05 (T)

ITEM V: REGULATORY TOOLS DEVELOPMENT

1. Quantitative Fire Hazard Analysis Tools - NUREG-1 805 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-1805 11/04 (C) o Publish hardbound NUREG-1805 with final spreadsheets 04/05 (C)

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 (C) o Review final NUREG prior to ACRS review 05/05 (C)

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 09/05 (T) o Review final V&V documents 12/05 (T)

4. American Nuclear Society (ANS) Fire PRA Standard 93

l MILESTONES I DATE (T1C) ]

o Review draft standard by NRR member of review committee 12/04 (C) o Review final standard by NRR member of review committee 10/05 (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 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)." and NEI 00-01, Rev. 1, "Guidance for Post-Fire Safe Shutdown Analysis". The staff will endorse this guidance in the final regulatory guide RG-XXXX, 'Risk-informed, Performance-Based Fire Protection for Existing Light-Water Nuclear Power Plants."

Proposed Actions: See Milestone chart.

Originating Document: SECY Paper 00-0009, "Rulemaking Plan, Reactor Fire Protection Risk-informed, Performance-Based Rulemaking", dated January 2000.

Regulatory Assessment: See Historical Background.

94

Current Status: The public comment period on the draft regulatory guide, DG-1 139, endorsing NEI 04-02, Rev. F has ended. The Staff incorporated the comments into the final regulatory guide and NEI revised NEI 04-02, Rev. F. The Staff gave ACRS and CRGR briefings on the Regulatory Guide and the comments we received are being resolved. Duke Power committed to transitioning all seven of their sites over the next five years and Progress Energy committed to transitioning all five of their sites over the next six years.

The Staff began planning for a Transition Pilot Program for Oconee and Harris sites. The OCFO approved a fee waiver for the pilot plants. NRR developed a fire protection inspection procedure to support the triennial inspection of the pilot plants. Presentations on NFPA 805 Rule were made at 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 Final Regulatory Guide RG-X.XXX, "Risk-lnformed, Performance-Based Fire Protection for Existing Light-Water Nuclear Power Plants", dated May 2005.

NEI 04-02, Rev. 0, "Guidance for Implementing a Risk-informed, Performance-Based Fire Protection Program Under 10 CFR 50.48 (c)", dated May 2005 NEI 00-01, Rev. 1, "Guidance for Post-Fire Safe Shutdown Analysis," dated January 2005.

NUREG/BR-0312, -The Alternate Fire Protection Regulation", dated September 2004.

Draft Regulatory Guide DG-1 139, "Risk-informed, Performance-Based Fire Protection For Existing Light-Water Nuclear Power Plants", dated October 2004.

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.

SECY Paper 00-0009, "Rulemaking Plan, Reactor Fire Protection Risk-Informed, Performance-Based Rulemaking", dated January 2000.

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 M04051 1A, "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, "Performance-based Standard for Fire Protection for Light Water Reactor Electric Generating Plants," 2001 Edition", dated May 2004.

95

ITEM II: POST-FIRE SAFE-SHUTDOWN CIRCUIT ANALYSIS RESOLUTION Historical

Background:

The goal of the Post-Fire Safe-Shutdown Circuit Analysis program is to clarify regulatory expectations with respect to circuit analyses and 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 28h 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 restarted 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, the staff issued Revision 1 to RIS 2004-03. A second RIS and a GL were developed to clarify compliance expectations and terminology specific to post-fire safe-shutdown circuit analysis. Both the Leadership and Executive Teams approved issuance of these generic communications. RIS 2005-XX, "Clarification of Post-Fire Safe-Shutdown Circuit Regulatory Requirements," was issued for public comment in May 2005. The staff plans to issue a Generic Letter for public comment in August 2005.

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.

"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.

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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-1778, "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.

Regulatory Issue Summary 04-03, "Risk-Informed Approach for Post-Fire Safe-Shutdown Associated Circuit Inspections", dated March 2004.

Regulatory Issue Summary 04-03, Rev. 1, "Risk-informed Approach for Post-Fire Safe-Shutdown Circuit Inspections", dated December 2004.

Regulatory Issue Summary 2005-XX, Draft, "Clarification of Post-Fire Safe-Shutdown Circuit Regulatory Requirements", dated May 2005.

Generic Letter 05-XX, Draft, "Post-Fire Safe-Shutdown Circuit Analysis Spurious Actuations", dated June 2005.

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 III.P to allow ex-Control Room operator manual actions as a Section III.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.

For further information, see Attachment 2, "NRR Rulemaking" DRIP RM#616.

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 03-01 00, "Rulemaking Plan on Post-Fire Operator Manual Actions", dated June 2003.

SRM "Staff Requirements - SECY-04-0233 - Proposed Rulemaking - Post-Fire Operator Manual Actions (RIN 3150 AH-54)", dated January 18, 2005.

Communication Plan for Fire Protection Operator Manual Actions, dated January 26, 2005.

Draft Regulatory Guide DG-1 136, "Demonstrating the Feasibility and Reliability of Oiperator Manual Actions in Response to Fire", dated February 2005.

97

Summary of Meeting to Receive Stakeholder Feedback, dated May 16, 2005.

Public Comments on Proposed Rule, dated May 16, 2005.

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.

Hemyc Firewrap - RES performed testing on multiple configurations of 1-hour Hemyc and 3-hour MT fire wrap material to determine if the material can be rated as afire barrier based on approved test methods.

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 issue 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: RES completed testing for both conduit and cable tray configurations of the Hemyc fire wrap and conduit configurations for MT. (RES will issue a test report and notify the stakeholders).. NRR issued an IN and will be followed up with a generic letter. A communication plan has been prepared to further detail the activities surrounding this issue (ML050670609).

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, and the staff is preparing its response to the NEI white paper. NRC is reviewing NEI's recommendation and will provide a recommendation to the Inspection Program Branch (IIPB/DIPM/NRR).

An Information Notice was published on the RCP seal performance issue after the staff completed their review of the WOG report.

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NEI issued a white paper on the CO2 fire suppression systems topic in January of 2005. The staff will provide comments on the NEI white paper in July 2005.

NRR Lead Section Chief: Sunil Weerakkody, SPLB, 415-2870 NRR Technical Contacts: Dan Frumkin, SPLB, 415-2280 Naeem Iqbal, SPLB, 415-3346 Phil Qualls, SPLB, 415-1849 Robert Wolfgang, SPLB, 415-1624 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.

NEI White Paper on Epoxy Coatings, June 28, 2004.

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.

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.

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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.

RegulatorV 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 (FDTs) 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 with the final NUREG being prepared for ACRS review in May; the Fire Modeling V&V will be available in draft form by April 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.

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.

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PHASED APPROACH TO PRA QUALITY TAC No. MC1747 Last Update: 06/30/05 Lead Division: DSSA Supporting Office: RES CTL: N/A GSI No.: N/A TASK MILESTONE DATE (T/C) 1.1 Identify current risk-informed applications (e.g., 50.69) 03/31/04 (C) 1.2 Specify PRA quality needs for each risk-informed application 12/30/04 (C) 1.3 Phase 2 Guidance Document Schedule 12/31/04 (C) 1.4 Revise application-specific guidance to address PRA quality 12/30/05 (T)

PRA quality (RG 1.200) pilots for internal events 02/28/05 (C)

Implementation - quality for internal events PRA (Note 1) 12/30/06 (T)

Standards development - ANS fire PRA 06/30/06 (T)

NRC endorsement - ANS fire PRA standard 06/30/07 (T)

Implementation - quality for fire PRAs (Note 1) 06/30/08 (T)

Standards development - ANS low-power & shutdown PRA In ballot NRC endorsement - ANS low-power & shutdown standard 06/30/06 (T)

Implementation - quality for low-power & shutdown PRAs 06/30/07 (T) 1.5 Development of Prioritization Process for Staff Review 12/30/05 (T) 1.6 Phase 2 Implementation Schedule Note 4 1.7 Develop Phase 3 guidance 12/31/08 (T) 2.1 Alternate methods & treatment of uncertainties, draft NUREG 12/30/04 (C) 2.2 Standards development - ANS external events PRA (C)

NRC endorsement - ANS external events standard Note 3 Implementation - quality for external events PRAs (Note 1) Note 1 Note 1: It is assumed that the standards documents will lag behind the guidance documents for the applications. It is further assumed that a delay of one year between the completion of the quality guidance documents and that time at which each application is expected to conform to those documents is sufficient for the review of the associated PRA elements to be completed. Furthermore, this time delay allows for the staff infrastructure necessary to transition to Phase 2 to be developed.

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Note 2: Primary lead organization is RES with input from NRR.

Note 3: Initial staff review of ANS standard was issued for public comment in August 2004. ANS is revising the standard to respond to those comments, but it has not been issued to date.

Note 4: The schedule is dependent on the schedule for task 1.3. Based on informal feedback, the original proposal date of one year may be unrealistic given the resources available to perform the task.

==

Description:==

The objective of the phased approach to stabilizing the PRA quality expectations and requirements is to achieve an appropriate level of PRA quality for NRC's risk-informed regulatory decisionmaking. The phased approach defines the needed PRA quality for current or anticipated applications and the process for achieving this quality, while allowing risk-informed decisions to be made using currently available methods until all the necessary guidance documents defining the PRA quality are developed and implemented.

It is expected that meeting the phased approach objective will result in the following:

a. Industry movement towards improved and more complete PRAs

b. Increased efficiencies in the staff's review of risk-informed applications

c. Clarification of expectations for 10 CFR 50.46 and 10 CFR 50.69 rulemakings

d. Continued near-term progress in enhancing safety through the use of available risk-informed methods while striving for increased effectiveness and efficiency in the longer term An additional objective is to ensure that activities are coherently and properly integrated such that they complement one another and continue to meet the 1995 PRA Policy Statement.

There are three Phases defined. Each phase is characterized in terms of the available guidance documents relative to the risk-informed activities. What distinguishes the phases is the availability and implementation of technical guidance documents that address the use and quality of the PRA with scope and level of detail necessary to support an application.

Phase 1 corresponds to the current status of the use of PRA in regulatory decisionmaking. Guidance for using PRA in regulatory decisionmaking exists in the form of regulatory guides such as RG 1.174, 1.175, 1.176, 1.177, and 1.178. These guides address PRA quality in a general way, stating that the quality of the PRA must be "commensurate with the application for which it is intended and the role the PRA results play in the integrated decision process." They do not, however, provide detailed guidance on what is technically adequate for the defined scope. The review of the base PRA used to support applications has been based on the reviewers' experience guided by previous staff reviews such as those performed on the Individual Plant Examinations (IPE) submittals, and on observations from peer reviews that were performed for the licensee. However, until recently there has been no formal guidance on PRA technical adequacy. The focus of the reviews has, in general, been on those aspects of the PRA that contribute to the evaluation of the change in the CDF and LERF associated with the application, with particular attention to those aspects of the licensee's PRA that have been identified as potential concerns in previous reviews.

Phase 2 corresponds to the situation where, for each general application type (such as risk-informed Inservice Inspection (ISI) applications, risk-informed technical specifications applications, and 10 CFR 50.69 applications), the baseline PRA that supports the application meets applicable consensus standards, such as the ASME PRA Standard as endorsed in RG 1.200. Furthermore, the PRA scope is such that all operational modes and initiating events that could change the regulatory decision substantially are included in the model quantitatively. Thus, for a specific application type to be considered Phase 2, guidance must be in place for (1) performing the PRA analyses needed to support the application, and 102

(2) assessing whether the level of detail and technical adequacy of the PRA models for the significant modes of operation and initiating events (i.e., those whose inclusion could change the regulatory decision substantially) is sufficient to support the application.

In Phase 3, the regulatory framework is in place (i.e., guidance documents are available) for the operational modes and initiating events that could affect a decision for existing and planned risk-informed applications.

Therefore, to transition to Phase 3, a licensee will need a PRA that is of sufficient scope (in terms of operational modes and initiating events) to address currently envisioned applications and will meet the requirements of the applicable industry consensus standards.

Background:

The Commission, by publishing its Final Policy Statement on the Use of Probabilistic Risk Assessment Methods in Nuclear Regulatory Activities (Ref. 1), reflected its belief that an overall policy on the use of probabilistic risk assessment (PRA) methods in nuclear regulatory activities should be established so that the many potential applications of PRA would be implemented in a consistent and predictable manner that would promote regulatory stability and efficiency. Furthermore, the Commission stated its belief that the use of PRA technology in NRC regulatory activities should be increased to the extent supported by the state-of-the-art in PRA methods and data and in a manner that complements the NRC's deterministic approach. With implementation of this policy statement, the Commission also recognized, and encouraged, continuation of industry initiatives to improve PRA methods, applications, and data collection to support increased use of PRA techniques in regulatory activities.

Since the PRA Policy Statement was issued, a number of risk-informed activities have been undertaken and a number of documents have been written by both the staff and industry that provide guidance on the use of PRA information in the risk-informed reactor regulatory activities, and on PRA quality.

• Reactor owners groups have been developing and applying a PRA peer review program for several years. In a letter dated April 24, 2000, the Nuclear Energy Institute (NEI) submitted NEI-00-02 (Ref. 2) to the NRC for review in the context of the staff's work to risk-inform the scope of special treatment requirements contained in 10 CFR Part 50 (discussed in SECY-99-256, Ref. 3).

On August 16, 2002, NEI submitted draft industry guidance for self-assessments (Ref. 4) to address the use of industry peer review results in demonstrating conformance with the American Society of Mechanical Engineers (ASME) PRA standard. This additional guidance, which is intended to be incorporated into a revision of NEI-00-02 (per NEI, see Reference 4), contains:

- Self-assessment guidance document

- Appendix 1 (actions for industry self assessment)

- Appendix 2 (industry peer review subtier criteria)

PRA standards have been under development by the ASME and the American Nuclear Society (ANS). On April 5, 2002, ASME issued a standard for a full-power, internal events (excluding internal fire but including internal floods) Level 1 PRA and a limited Level 2 PRA, supplemented by addenda on December 5, 2003 (Ref. 5). In December 2003, ANS issued a standard for external events (Ref. 6), which addresses seismic, high wind, external flood, and other (e.g., aircraft crash, chemical release) hazards. In the future, ANS plans to issue standards for PRAs for evaluating internal fire risk and risk from low-power and shutdown modes of operation.

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RG 1.200 (Ref. 7), "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," issued for trial use. RG 1.200 is expected to provide the level of confidence that the technical adequacy of the PRA is sufficient to support the identified applications such that an in-depth technical review by NRC staff would not be needed to ensure its quality to support the applications. This regulatory guide (RG) will allow staff members to focus their review on key assumptions and areas identified by peer reviewers as being of concern and relevant to the application. Consequently, RG 1.200 will provide for a more focused and consistent review process.

On December 18, 2003, the Commission provided a staff requirements memorandum (SRM) (Ref. 8) regarding stabilizing PRA quality expectations and requirements. In the SRM, the Commission approved implementation of a phased approach to achieving an appropriate quality for PRAs for NRC's risk-informed regulatory decisionmaking. This phased approach was described in an attachment to the SRM. The SRM also directed the staff to develop an action plan that would define a practical strategy for the implementation of the phased approach to PRA quality.

Proposed Actions: The milestones listed in the milestone table comprise the actions for this initiative. The only additional task is to develop a communication plan. The objectives of this plan are to, (1) explain the staff activities to stakeholders, (2) describe the staff's approach, and (3) provide a structure for communicating the messages to stakeholders. This communication plan is scheduled for development in the third quarter of the fiscal year 2005.

Originating Documents: None.

Regulatory Assessment: Not applicable.

Current Status: The December 30, 2004, milestone for Task 1.4, completion of the RG 1.200 pilots was delayed by two months due to the licensees; late submittals. However, this delay will not affect the plan completion date of December 31, 2008.

Work has begun on Task 1.5, with an initial meeting between DSSA and DLPM staff on December 17, 2004. The development of the prioritization process under Task 1.5 will be coordinated with ongoing activities within DLPM, scheduled to be completed for implementation in FY2006.

Task 1.6 provides for a phasing in of the expectations for submittals to allow licensees time to develop PRA models, and perform the necessary peer reviews or self assessments to demonstrate conformance with the appropriate standards, once those standards have been developed and endorsed by NRC. The schedule for this phasing in is dependent on the schedule in Task 1.3. Based on informal feedback received by the MSPI PRA quality task group, the original proposal of one year for a delay in full implementation by the licensees, may be unrealistic given the resources available to perform these tasks.

This will be revisited as more experience is obtained.

A draft NUREG entitled "Guidance on Alternative Methods and the Treatment of Uncertainties in Risk-Informed Decisionmaking", developed by RES, was issued for internal NRC staff review per the schedule (December 31, 2004). This has been reviewed by DSA staff and a revision to the document is planned for issuance for public comment in October 2005.

Contacts:

NRR Technical

Contact:

Gareth W. Parry, NRR/DSSA, 415-1464 RES Lead

Contact:

Mary T. Drouin, RES/PRAB, 415-6675 104

References:

1. USNRC, "Use of Probabilistic Risk Assessment Methods in Nuclear Activities: Final Policy Statement," Federal Register, Vol. 60, p. 42622 (60 FR 42622), August 16,1995.

2. Nuclear Energy Institute, "Probabilistic Risk Assessment Peer Review Process Guidance,"

NEI-00-02, Revision A3, March 20, 2000.

3. USNRC, SECY-99-256, "Rulemaking Plan for Risk-informing Special Treatment Requirements,"

October 29, 1999.

4. Letter from NEI, Anthony Pietrangelo, Director of Risk and Performance Based Regulation Nuclear Generation, to the USNRC, Ashok Thadani, Director of Office of Nuclear Regulatory Research, December 18, 2001.

5. American Society of Mechanical Engineers, "Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications," ASME RA-S-2002, April 5, 2002, and "Addenda to ASME RA-S-2002," ASME RA-Sa-2003, December 5, 2003.

6. American Nuclear Society, "American National Standard External-Events PRA Methodology,"

ANSI/ANS-58.21 -2003

7. USNRC, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," Regulatory Guide 1.200, for trial use, February 2004.

8. USNRC, COMNJD-03-0002 "Stabilizing the PRA Quality Expectations and Requirements."

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ATTACHMENT 2 GENERIC COMMUNICATION AND COMPLIANCE ACTIVITIES

Open Generic Communication TACs (PA No. 101122CA/B)

Summary Report as of 06130/2005 TAC NO. TAC TITLE ACE LEAD ORC MC6913 BL: Emergency Preparedness and Response Actions for Security-Based Events (Casto-NSIR/Markley-DIPM) 2 NSIR MC7021 GL: Assurance of Industry Implementation of Key Shutdown Voluntary Initiatives (Pohida-DSSAIMarkley-DIPM) 2 DSSA MC6496 GL: Failures of InaccessiblelUnderground Cables That Disable Accident Mitigation Systems (Koshy-DE/Markley-DIPM) 4 DE MC5657 GL: Grid Reliability and the Impact on Plant Risk and the Operability of OffsIte Power (Lazevnick-DEIMarkley-DIPM) 6 DE MC6893 GL: Managing Gas in Emergency Core Cooling Systems (Lyon-DSSA/Markley-DIPM) 2 DSSA MC6498 GL: Post-Fire Safe-Shutdown Circuit Analysis Spurious Actuations (Wolfgang-DSSANMarkley-DIPM) 4 DSSA MC6921 GL: Potentially Degraded HEMYC/MT Electrical Raceway Fire Barrier Systems (Lavretta-DSSA/Markley-DIPM) 2 DSSA MC6635 GL: Primary Water Stress Corrosion Cracking in Butt Welds (Sullivan-DE/Markley-DIPM) 3 DE MC2470 GL: Steam Generator Tube Integrity and Associated Technical Specifications (Karwoski-DE/Markley-DIPM) 16 DE MC6735 IN: Failure to Evaluate the Effect of Plant Configuration Changes on the Emergency Plan (Johnson-NSIR/King-DIPM) 3 NSIR MC5857 IN: Fire In Electrical Distribution Systems and Its Impacts on Security Equipment (Tabatabai-DIPM/) 5 DIPM MC7265 IN: Kewaunee - Plant Design May Not Mitigate Consequences of Turbine Building Flooding (Kozak-R3/Telson-DIPM) 1 R3 MC6949 IN: Movement of Supports in Steam Generators (Yoder-DE/Hodge-DIPM) 2 DE MC6230 IN: Nonconservatism in Leakage Detection Sensitivity (Hodge-DIPM/) 5 DIPM MC5890 IN: Potential Turbine Overspeed Due to Load Rejection & Failure of the Turbine Bypass Valves to Open (Tabatabal- 5 DIPM DIPM/)

MC6953 IN: San Onofre - Vibration-induced Failure of Fisher Butterfly Valves (Scarbrough-DE/Schmitt-DIPM) 2 DE MC6708 IN: Switchyard Breakers (Koshy-DE/Laura-DIPM) 3 DE MC6497 RIS: Clarif of Implementing Guidance for Comp Measures Related to Access Autho Orders (Canady-NSIR/Markley- 4 NSIR DIPM)

MC6655 RIS: Clarifi of Reqmts for Appl of the ASME Code Symbol Stamp on Safety Related Components (Sekerak-DE/Markley- 3 DE DIPM)

MC6738 RIS: Clarification of NRC Guidelines for Control of Heavy Loads (Jones-DSSAIMarklay-DIPM) 3 DSSA MC6266 RIS: Clarification of Post-Fire Safe-Shutdown Circuit Regulatory Requirements (Radlinski-DSSA/Markley-DIPM) 4 DSSA MC6782 RIS: Control of Sensitive Unclassified Non-Safeguards Info Related to Nucl Pwr Reactors (Reckley-DLPM/Markley- 3 DLPM DIPM)

MC2262 RIS: GL 91-18, Rev 2-Guidance on Operability & Resol of Degraded & Non-Cnfrming Conditions (Boyce-DIPMWMarkley- 12 DIPM DIPM)

MC4220 RIS: Guidance for Establishing and Maintaining a Safety Conscious Work Environment (Jarriel-OE/Markley-DIPM) 11 OE MC5381 RIS: Issuance of NRC Management Directive 8.17, Licensee Complaints Against NRC Employees (Allsopp- 7 DIPM DIPM/Markley-DIPM)

MC6993 RIS: NRC Incident Response and the National Response Plan (Kevem-NSIR/Markley-DIPM) 2 NSIR MC6900 RIS: NRC Staff Position on 10 CFR 50.36, 'Tech Spec', Instrument Setting Requirements' (Gratton-DLPM/Markley- 2 DLPM DIPM)

MC6647 RIS: Recent Experience from BWR Instability Events (Huang-DSSA/Markley-DIPM) 3 DSSA Tuesday, July 26, 2005 Page 1 of 2

TAC NO. TAC TITLE AGE LEAD OR6 MC5858 RIS: RIS 2002-15, Rev 1-NRC Approval of Comm Data Encryption Sys for Electronic Trans of SGI (Lee-NSIR/Markley- 5 NSIR DIPM)

MC5252 RIS: Scope of For-Cause Fitness-for-Duty Testing Required by 10 CFR 26.24(a)(3) (Canady-NSIR/Markley-DIPM) 7 NSIR MC5826 RIS: Issuance of NUREG-1482, Rev 1-Guidelines for Inservice Testing At Nucl Pwr Plants (Unikewicz-DE/Markley- 5 DE DIPM)

MC6734 RIS: RIS 2003-18, Sup 2 - Use of NEI 99-01, Methodology for Dev of Emerg Actn Levels, Rev 4 (Johnson- 3 NSIR NSIR/Markley-DIPM)

Tuesday, July 26, 2005 Page 2 of 2

Closed Generic Communication TACs (PA No. 101122CA/B)

Summary Report (04101/2005 - 0613012005)

TAC NO. TAC TIE Si[ATUS AGE TAC CLOSED LEAD OR6 MC2590 GL: Ultrasonic Flow Meters (Ahmed-DE/Markley-DIPM) W 14 06/21/2005 DE MC5142 IN: Blocked Floor Drains & Non-Water-Tight Equipment Floor Plugs Increase Flooding Risk (Blamey-Rlfrelson- C 6 05/1912005 RI DIPM)

MC5656 IN: Failure to Maintain Alert and Notification System Tone Alert Radio Capability (Flemming-NSIR/Kramer- C 3 04/13/2005 NSIR DIPM)

MC6269 IN: Monitoring Vibration to Detect Circumferential Cracking of Rx Coolant Pump & Rx Recirc Pump Shafts C 1 04/19/2005 DIPM (Telson-DIPMI)

MC6515 IN: Reactor Coolant Pumps Seal Cooling (Qualls-DSSAlHodge-DIPM) C 3 06/14/2005 DSSA MC6510 IN: Results of Hemyc Electrical Raceway Fire Barrier System Full Scale Fire Testing (Frumkin-DSSANHodge- C 1 04/15/2005 DSSA DIPM)

MC5225 IN: Steam Generator Tube Crack Indication Issues (Karwoskl-DE/Tabatabal-DIPM) C 4 04/21/2005 DE MC5178 IN: Three Unit Trip and Loss of Offsite Power at Palo Verde (Pal-DE/Hodge-DIPM) C 7 06/14/2005 DE MC6499 RIS: Endorsement of NEI Pos Paper 'Range of Protective Actions for Nucl Pwr Plant Incidents' (Moody- C 4 06/21/2005 NSIR NSIR/Markley-DIPM)

MC5251 RIS: Guidance on Prot of Unattended Openings That Intersect a Security Boundary or Area (Tardiff- C 7 04/28/2005 NSIR NSIR/Markley-DIPM)

MC6383 RIS: High Security Protected and Vital Area Barrier Breaching Analysis (McKirgan-NSIR/Markley-DIPM) C 4 06/20/2005 NSIR MC3628 RIS: Performance of Manual Actions to Satisfy the Reqmts of IOCFR Part 50, App R, Sec III.G.2 (Klein- C 11 05/03/2005 DSSA DSSA/Markley-DIPM)

MC4577 RIS: Regulatory Issues Regarding Criticality Analyses For Spent Fuel Pools & ISFSIs (Taylor-DSSA/Markley- C 9 04/06/2005 DSSA DIPM)

Tuesday, July 26, 2005 Page 1 of 1