ML101940442

Response to ACE Letter June 7, 2010, Relating to Fire Protection at the Limerick Generating Station

ML101940442
Person / Time
Site:	Limerick
Issue date:	07/13/2010
From:	Paul Krohn Reactor Projects Region 1 Branch 4
To:	Cuthbert L Alliance For A Clean Environment
KROHN P, RI/DRP/PB4/610-337-5120
References
Download: ML101940442 (290)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION REGION I 475 ALLENDALE ROAD KING OF PRUSSIA, PA 19406-1415 July 13, 2010 Dr. Lewis Cuthbert Alliance for a Clean Environment 1189 Foxview Road.

Pottstown, PA 19465

SUBJECT:

RESPONSE TO ACE LETTER DATED JUNE 7, 2010, RELATING TO FIRE PROTECTION AT THE LIMERICK GENERATING STATION

Dear Dr. Cuthbert:

We are in receipt of your lelter of June 7, 2010, in which you posed a number of questions relating to fire protection at Limerick Generating Station (Limerick).

Your June 7 letter referred to your letter of January 12, 2009, and claimed we failed to answer your specific question. Our response, dated March 10, 2009, stated that "The Nuclear Regulatory Commission (NRC) has determined that Limerick is in compliance with all fire safety rules .... " I have enclosed a copy of that lelter as well as hard copies of documents referenced in the response to the fire protection questions you posed in your March 2009 letter. Please note that the referenced inspection procedures have been revised in the past year. The copies I am sending are the most up-to-date versions.

You also asked what NRC accepts from licensees as proof that plants are "safe enough." I have enclosed a copy of NRC's Standard Review Plans for fire protection plans. Standard Review Plans establish criteria that the NRC uses in evaluating whether a licensee meets NRC regulations. There are. two versions, one for plants with deterministic fire protection plans, and one for plants implementing risk-informed performance-based plans in accordance with NFPA 805. In addition, I have included a copy of NRC's Fire Protection Regulations, as set forth in Title 10 of the Code of Federal Regulations, Part 50.48. Finally, a copy of the NRC's Safety Evaluation Report of Limerick's Fire Protection Systems (NUREG-0991) is attached. '

In the attachment to this letter, I have provided responses to the specific questions relating to Limerick which you posed in your June 7, 2010 letter.

D. Cuthbert 2 I trust that this information is responsive to your needs. If you should have any further questions or require additional information, please do not hesitate to contact us.

Sincerely, Paul G. Krohn, Chief Projects Branch 4 Division of Reactor Projects Docket Nos. 50-352, 50-353 License Nos. NPF-39, NPF-85

Enclosures:

As Stated

1. ACE Questions on Limerick Fire Safety

2. ACE letter to NRC, June 7, 2010

3. Attachment 71111.05T

4. Attachment 71111.05AQ

5. NRC Inspection Report 05000352/2007006, 05000353/2007006

6. NRC Inspection Report 05000352/2010006,05000353/2010006

7. NRC letter to ACE, March 10, 2009

8. NRC Inspection Report 05000352/2008002, 05000353/2008002

9. NRC Inspection Report 05000352/2008003, 05000353/2008003

10. NRC Inspection Report 05000352/2008004, 05000353/2008004

11. NRC Inspection Report 05000352/2008005, 05000353/2008005

12. Standard Review Plan, 9.5.1.1, Fire Protection Program

13. Standard Review Plan, 9.5.1.2, Risk-Informed, Performance-Based Fire Protection Program

14. 10 CFR 50.48 Fire Protection

15. Safety Evaluation Report, Limerick Generating Station, Units 1 and 2

ACE Questions on Limerick Fire Safety Fire Induced Circuit Faults Is Exelon fully in compliance with NRC's fire-induced circuit fault regulations at Limerick Nuclear Power Plant? Or, Is Exelon claiming Limerick Nuclear Plant is "safe enough" to avoid meeting the most protective fire-induced circuit fault regulation and what credible specific evidence of "safe enough" at Limerick has Exelon provided to NRC?

The NRC fire protection requirements for Limerick Generating Station (Limerick) are delineated in the facility operating licenses for the plants. Limerick is in compliance with those requirements.

Alternative Fire Protection Rule

1) Is Limerick Nuclear Power Plant in full compliance with the most stringent fire regulations?

Limerick is in compliance with all applicable NRC fire protection requirements.

2) OR, Is Limerick one of the 47 reactors that won't even commit to immediately adopting the weaker standards?

Not Applicable.

3) Specifically, as of June 2010, has Limerick adopted NFPA 805 and is Limerick in full compliance with that?

Limerick has not committed to adopting NFPA 805, "Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants," nor is Limerick required to do so.

Fire Barriers

1) What is the current state of fire barrier use at Limerick Nuclear Power* Plant?

Limerick uses a number of different types of fire barriers. The fire barriers between fire areas are primarily monolithic reinforced concrete walls, floors and ceilings.

Some fire barriers separating fire areas are comprised of concrete block walls, and several barriers which NRC required to be installed during the licensing process are constructed of gypsum wallboard, in accordance with Underwriters Laboratories listed designs. Limerick also uses electrical raceway fire barrier systems (ERFBS) to protect cables important to safe shutdown in some fire areas.

All fire barriers in use at Limerick are fully qualified for the hazards they protect against.

2) Is Limerick still using Thermo-Lag or Hemyc anywhere on the site?

Limerick uses Thermo-Lag as a fully qualified one hour rated ERFBS in several fire areas. Limerick does not employ Hemyc in any fire areas.

3) Please provide the complete review done on Limerick's individual use of ERFBS.

The review of Limerick's use of ERFBS is documented in the plant specific Safety Evaluation Report issued for the licensing of the units (NUREG-0991) and supplements. I have enclosed the relevant portions. In addition, a sample of Limerick's fire barriers are reviewed during each fire protection inspection. I have enclosed a copy of Limerick's most recent Triennial Fire Protection Team Inspection, which looked specifically at the qualifications of ERFBS at Limerick. In addition, fire barriers are inspected every quarter by the resident inspectors as part of their fire protection tours. You will find these inspections documented in the quarterly integrated inspection reports provided.

4) Has limerick applied for exemptions?

Limerick has not applied for any exemptions from NRC fire protection requirements.

5) Has Limerick received any exemptions?

Limerick has not been granted any exemptions from NRC fire protection requirements. This is reflected in the NRC's Fire Protection Exemption database.

Alliance .For A Clean. Environment Pottstown, PA 19465 June 7,2010 Paul Krohn, NRC Branch Chief NRC, Region 1 475 Allendale Road King of Prussia, PA 19406-1415 RE: NRC's 5/25/10 Meeting and Unprotective Fire Safety Policies

Dear Mr. Krohn,

This letter is a follow-up to the NRC meeting at the Limerick Township Building May 25,2010 regarding fire safety. Many of NRC's responses to our concerns and questions need to be clarified. Since different NRC individuals appear responsible for specific issues, we deCided to ask NRC to respond to each issue separately about which we have concerns and questions. ACE will be sending separate letters about several issues discussed with us at NRC's meeting plus issues from our review of NRC fact sheets provided at that meeting.

In this letter we will address our long-term fire safety concerns at Limerick Nuclear Power Plant. ACE first contacted you about Limerick's fire safety January 12, 2009. Your response failed to answer our specific questions. At thE) May 6, 2010 Exelon public relations event, NRC representatives still failed to answer if Limerick was in full compliance with all fire safety regulations. We were told NRC would be prepared to answer that questions at the 5/25/10 NRC meeting.

The NRC official presented to us at the 5/25/10 meeting as the NRC expert on fire safety was vague and unresponsive to our request for a simple yes or no answer to our question about whether Limerick is in full compliance with fire safety regulations. Most di~turbing was his casual attitUde about what we view as a crucial issue. Full compliance with fire safety regulations can help to prevent a fire that could cause a meltdown and disaster at Limerick Nuclear Power Plant in our region. After what has happened in the Gulf, and knowing that fires at nuclear plants can lead to a nuclear plant meltdown and disaster, we think NRC should be taking a far more serious and protective approach to strict nuclear plant compliance with fire safety regulation.

NRC's fire safety expert said to get a yes or no we would have to be specific. We object to his assertion that the public is expected to know fire safety regulatory details to get a straight yes or no answer about Limerick's full compliance with fire safety regulations. After repeated requests, he finally claimed Limerick was in full compliance .. He handed us NRC fire safety fact sheets, none of which turned out to be anything specific about Lime;rick's fire safety compliance, which was the pOint of our question.

After careful review of NRC's fire safety fact sheets we are more concerned than ever. It appears NRC caved in to the nuclear industry, just like MMS with deep sea mining safety. ACE identified the issues below. We are requesting detailed written responses to each comment and question.

Fire-Induced Circuit Faults These have the potential to cause maloperation of plant equipment important to safe shutdown. In 1998, NRC identified inconsistency between positions of th{l industry and NRC regarding regulations concerning fire-induced circuit failures.

• To avoid NRC enforcement for industry non-compliance, NRC irresponsibility instituted enforcement discretion, allowing the industry to implement compensatory measures, such as staging fire watches for identified circuit failure.

• When NRC or nuclear plant operators identify a fire-induced circuit failure issue, NRC has irresponsibly allowed nuclear plant owners that can't meet requirements, to apply to NRC for Enclosure 2

permission to deviate from regulatory requirements by demonstrating to NRC they can ensure they are safe enough.

ACE believes it is negligent for NRC to allow nuclear plant owners to avoid full compliance with fire safety requirements for fire-induced circuit faults simply by claiming to demonstrate they are "safe enough".

v" "Safe Enough" is an unsubstantiated term that can't be justified. This highly subjective standard is not sufficiently protective, given the potential for a fire to turn into a meltdown with disastrous consequences. What does "safe enough" mean? Something is only "safe enough" until it isn't, as in the Gulf of Mexico.

v" It seems impossible to prove anything is "safe enough", short of starting a fire. Explain with specific details what NRC accepts from nuclear plant owners as proof that their plants are "safe enough" without full compliance with NRC's fire-safety regulatory requirements.

Violations and fines for failing to fully meet fire-induced circuit fault regulations will not be imposed on the nuclear industry by NRC.

v" Where is the incentive for nuclear plant owners to comply with NRC fire safety requirements?

NRC caved in to the industry. NRC failed to hold licensees fully accountable, allowing the nuclear industry to avoid full compliance with regulations and enforcement for violations.

v" This is yet another example of why the public believes NRC is more interested in protecting nuclear industry profits over public safely.

Questions about Limerick:

1) Is Exelon fully in compliance with NRC's fire-induced Circuit fault regulations at Limerick Nuclear Power Plant?

2) OR, is Exelon claiming Limerick Nuclear Plant is "safe enough" to avoid meeting the most protective fire-induced circuit fault regulations and what credible specific evidence of "safe enough" at Limerick has Exelon provided to NRC?

Given w\,!atis at stake for our region, there is no acceptable excuse for Exelon to avoid full compliance with fire-induced circuit faults.

"Enforcement Discretion" is NOT PROTECTIVE With much at stake with fire safety regulations, NRC, the agency responsible for protecting public safety, should end any nuclear industry "enforcement discretion". NRC is playing with fire. After what happened in the Gulf of Mexico, it is time for NRC to stop blindly dismissing the potential for disastrous consequences from a fire at a nuclear plant.

Facts show cause for concern.

• June 3,1999 NRC documented additional problems and issued an Information Notice (IN) 99-17, "Problems Associated with Post-Fire Safe-Shutdown Circuit Analyses".

• December 2005, NRC issued a RegUlatory Issue Summary, "Clarification of Post-Fire Safe- Shutdown Circuit Regulatory Requirements."

• April 2009, NRC Proposed Revision 2 of Regulatory Guide (RG) 1.189, "Fire Protection for Nuclear Power Plants" - Guidance of analyzing and addressing fire-induced circuit failures.

v" From 1998 to date (12 years) NRC has failed to require full compliance with its fire-induced circuit fault regulations, in spite of the potential for disastrous consequences.

v" NRC claims "enforcement discretion" is not permanent, yet NRC allowed "enforcement discretion" continues to this day. That is both unprotective and unacceptable.

>>0 It's long past time for NRC to stop caving in to the demands of the nuclear industry to protect their bottom line, and instead demand that the nuclear industry get in full compliance with the most stringent fire safety regulations.

Alternative Fire Protection Rule

In 2001, in lieu of NRC's existing fire protection licensing basis, NRC modified its fire protection regulations to allow nuclear owners to adopt, on a voluntary basis, National Fire Protection Association (NFPA) Standard 805.

• For NRC to reduce so-called "unnecessary regulatory burdens" and "industry exemption requests" associated with the current deterministic approaches was clearly to accommodate the nuclear industry, not for public safety. NRC should not have provided a "voluntary" alternative to NRC's more protective fire protection rule.

Troubling Issues NRC abandoned more stringent original requirements to endorse the NEI and industry suggested "flexibility", reduced regulatory burdens, and weakened regulations to avoid exemptions.

~ NRC put nuclear industry profits ahead of public safety. NRC acquiesced to nuclear industry convenience over public safety.

• With a vested interest in the outcome, the Nuclear Energy Institute (NEI) and the nuclear industry developed the guidance accepted by NRC for implementing this new fire safety program involving more nuclear industry flexibility and reducing the regulatory burden associated with fire protection requirements, and reducing the need for licensee exemptions to current requirements.

~ "Flexibility" for nuclear plant owners should be a far lower priority to NRC than insuring public safety.

• . "Flexibility" provides convenience for the nuclear industry and likely improves their bottom line, but it clearly does not provide increased protection against fires.

~ Original fire safety regulations were established to prevent a nuclear disaster as a result of a nuclear plant fire. Allowing less stringent fire safety regulations increases risks. NRC reduced regulatory requirements to accommodate the wishes of NEI and the nuclear industry to save time and money. NRC clearly valued nuclear industry profits over safety.

• NRC admits rules, developed by NEI and the nuclear industry, are expected to reduce regulatory burdens and the need for license exemptions and amendments, yet NRC approved these rules.

~ NRC can't even get the industry to comply with weaker regulations. NRC is giving the nuclear industry incentives and/or a 6 month extension to follow weaker regulations with which nuclear plant owners should gladly have complied in the past nine years.

• NRC provided certain enforcement discretion as an incentive for nuclear plant owners to adopt weaker NFPA 805 requirements than those required under licensing, yet nuclear plant owners are still resisting the weaker requirements .

./ 2006 NRC endorsed the nuclear industry proposal to provide timely clarification of issues emerging at plants transitioning to NFPA 805 .

./ March 2009, 51 reactor units had sent letters of intent, indicating commitment to adopt NFPA 805. NRC issued Revision 1 of RG. 1.205 December, 2009 .

./ 47 reactor units can request an extension of enforcement discretion time to 6 months after the 2nd pilot plant safety evaluation is issued.

Questions about Limerick:

1) Is Limerick Nuclear Power Plant in full compliance with the most stringent fire regulations?

2) Or is Limerick one of the 47 reactors that won't even commit to immediately adopting the weaker standards?

3) Specifically, as of June 2010, has Limerick adopted NFPA 805 and is Limerick in full compliance with that?

Fire Barriers Even after review of fact sheets, it is still unclear if NRC caved in to the nuclear industry regarding regulations and guidelines to ensure that nuclear plants can be safety shut down in the event of a fire.

Tests indicated the material used by the nuclear industry for fire barriers may not provide their designed fire rating. 1-hour and 3-hour rated Thermo-Lag fire barrier material failed to consistently provide its intended protective function.

There is widespread use of this questionable effective Thermo-Lag fire barrier material by the nuclear industry.

NRC issued numerous generic communications to inform licensees of Thermo-Lag failures and requested nuclear plant owners to develop plans to resolve any noncompliances with fire protection regulations .

./ In 1999 inspectors discovered the fire endurance tests at Shearon-Harris did not satisfy the Generic Letter.

./ NRC publicized conclusions that the fire barrier was indeterminate and began NEGOTIATIONS with the industry for an industry-led resolution .

./ The industry declined to lead this initiative for a fire barrier resolution .

./ NRC backed down and concluded corrective actions would not be required

./ NRC fire tests from 2001 to 2005 indicated that the material used by the nuclear industry did not achieve the fire endurance consistent with its rating .

./ In 2006, NRC issued Generic Letter 2006-03, "Potentially Nonconforming Hemyc and MT Fire Barrier Configurations".

September 2009, NRC published "Draft NUREG-1924, Electric Raceway Fire Barrier Systems in US Nuclear Power Plants" for public comment.

Questions about Limerick:

1. What is the current state of fire barrier use at Limerick Nuclear Power Plant?l

2. Is Limerick still using Thermo-Lag or Hemyc anywhere on the site? If so, in what areas?

3. Please provide the complete review done on Limerick's individual use of ERFBS.

4. Has Limerick applied for exemptions?

5. Has Limerick received any exemptions?

Since fires can trigger meltdowns and since fire barriers are designed and constructed to achieve specific fire resistance ratings, and to limit the spread of heat and fire and restrict the movement of smoke, we believe the public deserves clear, easy to understand answers, with full disclosure.

We were told by NRC's "fire expert" in order to get specific answers, we needed to ask specific questions. We spent much time carefully reviewing NRC fact sheets and we have attempted to do that in this letter. Given the potential for an unthinkable disaster at Limerick Nuclear Power Plant, ACE believes NRC now has a responsibility to answer all our specific questions and concerns in this letter, clearly and specifically. Please don't yet again send us more websites, more generic fact sheets, and more non-answer responses. We await your timely response .

tT~;;;(1~

O{!; Lewis Cuthbert ACE President

Cc: Senator Casey Senator Specter Congressman Sestak Congressman Gerlach Congressman Dent Governor Rendell Senator Rafferty Senator Dinniman Representative Quigley Representative Hennessey Representative Vereb

\

ATTACHMENT 71111.0ST INSPECTABLE AREA: Fire Protection (Triennial)

CORNERSTONE: Initiating Events

• Mitigating Systems EFFECTIVE DATE: January 1, 2010 INSPECTION BASES: Fire can be a significant contributor to reactor risk. In many cases, the risk posed by fires is comparable to or exceeds the risk from intemal events. The fire protection program shall extend the concept of defense in depth (DID) to fire protection in plant areas important to safety by:

(1) preventing fires from starting; (2) rapidly detecting, controlling, and extinguishing fires that do occur; and .

(3) providing protection for structures, systems, and components important to safety so that a fire that is not I

promptly extinguished by fire suppression activities will not prevent the safe shutdown (SSD) of the reactor.

Licensees are also expected to take. reasonable actions to mitigate postulated events that could potentially cause loss of large areas of power reactor facilities due to explosions or fires.

Interim Compensatory Measures Order EA-02-026 spanned a wide range of security-related actions required to be taken by power reactor licensees in response to the events of September 11, 2001. Section B.S.b of the Order dealt specifically with these postulated events. In response to this Order (and the subsequent requirements of 10 CFR SO.S4 (hh)(2>> licensees implemented alternative mitigating strategies intended to maintain or restore core cooling, containment, and spent fuel pool cooling capabilities under such circumstances. These are collectively referred to as B.S.b requirements.

LEVEL OF EFFORT: Every 3 years, an inspection team that includes inspectors who are knowledgeable in the areas of fire protection, reactor operations, and electrical inspections will conduct a design-based, plant-specific, risk-informed, on site inspection ofthe DID elements used to mitigate the consequences of a fire. The review will include an assessment of the licensee's capability of Issue Date: 12/24/09 1 IP 71111.0ST Effective Date: 01/01/10 Enclosure 3

problem identification and resolution of fire. protection issues.

In addition, every 3 years inspectors trained to review alternative mitigating strategies should review several mitigating strategies to ensure they remain feasible. Additionally, inspectors should review the storage, maintenance, and testing of B.S.b related equipment.

CHANGES IN SCOPE: For triennial inspections starting March 2006, the scope of this procedure has been changed to integrate inspection guidance for operator manual actions associated with licensee-initiated compensatory measures while the underlying performance deficiency (e.g. failure to meet the reqUirements of 10 CFR Part SO, Appendix R,Section III.G.2 or other plant specific licensing requirements) are corrected. The background, objectives, and specific guidance are provided in Section 02.02.11 B of this document.

71111.0S-01 INSPECTION OBJECTIVES 01.01 The inspection team will evaluate the design, operational status, and material condition of the licensee's fire protection program by verifying that the licensee's program includes:

a. adequate controls for combustibles and ignition sources inside the plant;

b. adequate fire detection and suppression capability;

c. passive fire protection features in good material condition;

d. adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features;

e. procedures, equipment, fire barriers, and systems that ensure the post-fire capability to safely shut down the plant; and

f. feasible and reliable manual actions when appropriate to achieve SSD Inspection Procedure 71111.0SAQ, Fire Protection (Annual/Quarterly) is designed to complement the triennial inspection in the areas of fire brigade capability and water supply and delivery system maintenance and adequacy. However, the team should consider the need for additional inspections in these areas based on previous assessments and potential issues.

01.02 Verify that B.S.b mitigating strategies are feasible in light of operator training, maintenance of necessary equipment, and any plant modifications.

Issue Date: 12/24/09 2 IP 71111.0ST Effective Date: 01/01/10

71111.05-02 INSPECTION REQUIREMENTS 02.01 Inspection Preparation

a. Every 3 years, an inspection team will select three to five risk-significant fire areas or zones (depending on the teams makeup, scope, and resources) and conduct risk-informed inspections of s~lected aspects of the licensee's fire protection program. The team may adjust the number of fire areas inspected during the inspection based on the complexity of issues.

The initial selection of areas to be inspected should be based on inputs from a senior reactor analyst (SRA), a fire protection specialist and an electrical engineer.

For each area the selection process will consider but will not be limited to the following:

1. A review of the fire hazard analyses

2. Potential ignition sources

3. The configuration and characteristics of combustible materials

4. Routing of circuits important to accomplish and maintain safe shutdown condition \

5. The licensee's fire protection and fire fighting capability

6. The licensee's use of operator manual actions The inspection should focus on post-fire safe shutdown capability and should inspect alternative or dedicated shutdown capability, as applicable.

b. As part of the team's inspection of fire protection issues, a review of B.5.b Mitigating Strategies should also be performed. The team should select one or more strategies to review; and part of this review should include a review of the storage, maintenance, and testing of B.5.b related equipment. When determining which strategies and equipment to review, the team should consider:

1. Strategies for which the licensee has modified the regulatory commitment since the last performance of this inspection (or the performance of TI 2515/171). Any such strategies should be the main focus of the inspection effort.

2. Complexity of the strategies.

3. Risk significance of the strategies.

4. Strategies from different categories. For the purpose of this inspection the Issue Date: 12/24/09 3 IP 71111.05T Effective Date: 01/01/10

mitigating strategies are broadly characterized as fire fighting, command and control, spent fuel pool (SFP), and reactor and containment related.

02.02 Fire Protection Inspection Activities. The inspection guidance is designed to verify that the systems required to achieve and maintain post-fire SSD are capable of controlling reactivity, reactor coolant makeup, reactor heat removal, process monitoring, and to support associated system functions, and that the licensee's engineering and licensing documents (e.g., NRC guidance documents, license amendments, safety evaluation reports (SERs), exemptions, deviations) support the selection of the designated systems and equipment.

The verification of fixed fire protection systems, including the installation, design, and testing of the systems, and their adequacy to control andlor suppress fires in each selected area, will be done against the code of record.

If a fire brigade drill is observed, the inspection team should consider the lines of inspection inquiry outlined in IP71111.0SAQ.

Manual actions not part of an NRC approved exemption or deviation used in lieu of one of the means specified in Appendix R,Section III.G.2 to ensure one ofthe redundant trains is free of fire damage will be accepted only as temporary compensatory measures and therefore will be evaluated using guidance provided in paragraph 02.02j.2 of this document.

If one of the redundant trains in the same fire area is free of fire damage by one of the specified means in paragraph III.G.2, then the use of operator manual actions, or other means necessary, to mitigate fire-induced operation or mal-operation to the second train may be credited without prior approval.

a. Protection of Safe Shutdown Capabilities.

Verify that the fire protection features in place to SSD capability, including power, control, and instrumentation cables, satisfy the separation and design requirements (for pre-1979 plantsSection III.G of Appendix R, and for reactor plants reviewed under the Standard Review Plan, license specific separation requirements).

b. Passive Fire Protection.

Verify through observation of material conditions that the fire ratings of fire area boundaries, raceway fire barriers, and equipment fire barriers meet the requirements for the fire hazards in the area.

Verify through review of installation or repair records that material of an appropriate fire rating (equal to the overall rating of the barrier itself) has been used to fill openings and penetrations and that the installation meets engineering design.

Verify through review of installation or repair records that material of an appropriate fire rating has been used as fire protection wraps and that the installation meets engineering design.

Issue Date: 12/24/09 4 IP 71111.0ST Effective Date: 01/01/10

For unusual installation configurations and/or application of unusual materials verify appropriate fire test data.

c. Active Fire Protection.

Verify and review the material condition, operational lineup, functionality, and design of fire detection systems, fire suppression systems, and manual fire fighting equipment.

• Verify that detection, and automatic and manual suppression systems are installed, tested, and maintained in accordance with the code of record and would adequately control and/or extinguish fires associated with the hazards of each selected area.

Verify that the design capability of suppression agent delivery systems meet the requirements of the fire hazards.

d. Protection From Damage From Fire Suppression Activities.

Verify that redundant trains of systems required for hot shutdown, which are located in the same fire area, are not subject to damage from fire suppression activities or from the rupture or inadvertent operation of fire suppression systems, and that the licensee has addressed each of the following:

1. A fire in a single location that may, indirectly, through the \production of smoke, heat, or hot gases, cause activation of automatic fire suppression that could potentially damage all redundant trains;

2. A fire in a single location (or inadvertent manual or automatic actuation, or rupture of a fire suppression system) that may indirectly cause damage to all redundant trains (e.g., sprinkler-caused flooding of other than the locally affected train).

3. Adequate drainage is provided in areas protected by water suppression systems.

e. Alternative Shutdown Capability.

1. Methodology.

Verify that the licensee's alternative shutdown methodology has properly identified the systems and components necessary to achieve and maintain SSD conditions for each fire area, room or zone selected for review.

Specifically determine the adequacy of the systems selected for reactivity control, reactor coolant makeup, reactor heat removal, process monitoring and support system functions.

Verify the licensee's engineering and/or licensing justifications (e.g., NRC guidance documents, license amendments, SERs, exemptions, deviations)

Issue Date: 12/24/09 5 IP 71111.05T Effective Date: 01/01/10

support th.e required performi3nce criteria of the selected systems and components.

Verify that hot and cold shutdown from outside the control room can be achieved and maintained with or without the availability of off-site power for fires in areas where post-fire SSD relies on manipulating shutdown equipment from outside the control room.

I Verify that the transfer of specified plant control functions from the control room to the alternative location(s) has been dernonstrated without being I

affected by fire-induced circuit faults (e.g., by the use of separate fuses and I power supplies for alternative shutdown control circuits).

2. Operational Implementation.

Verify that the training program includes an evaluation of alternative or dedicated safe shutdown capability for licensed and non-licensed personnel.

Verify that personnel required to place and maintain the plant in hot shutdown following a fire using the alternative dedicated shutdown system are properly trained and are available at all times from onsite shift staff, exclusive of the fire brigade.

Verify that adequate procedures for use of the alternative shutdown systern are in place.

Verify that human factors attributes were addressed in the development of the alternative shutdown procedures (e.g., placement and accessibility of equipment, environmental conditions, etc.). Consider conducting a walk down of the procedure step by step paying special attention to "the human factors elements.

Verify that the operators can reasonably be expected to perform and complete the instructions of the procedures within applicable shutdown time requirements. - see Section 11 B Verify that the licensee conducts periodic operational tests of the alternative shutdown transfer capability and instrumentation and control functions, and the tests are adequate to prove the functionality of the alternative shutdown capability .

f. Circuit Analyses.

Verify that the licensee has identified structures, systems, and components (SSCs) important to SSD and their dernonstrated compliance with 10 CFR Part 50.48.

Verify for the selected areas that the licensee has performed a post-fire SSD analysis.

Issue Date: 12/24/09 6 IP 71111.05T Effective Date: 01/01/10

Review specific process and instrumentation diagrams (P&IDs) for flow diversions, loss of coolant, or other scenarios which could adversely affect the nuclear power plants capability to achieve and maintain hot shutdown. Verify that the licensee's analysis identified and considered such processes and circuits, and that the analysis has shown that hot shorts, and/or shorts to ground will not prevent SSD.

Verify that the circuit analysis considered the following for the areas being evaluated:

1. Cable failure modes.

(a) For any single thermoplastic or thermoset multiconductor cable (including armored), review any combination of conductors within the cable (e.g. intra-cable) for which a short will cause spurious actuation(s). Inspectors should review 3 or 4 of the most critical combinations.

(b) For any 2 adjacent thermoplastic cables, review any combination of conductors between the two cables for which a short will cause spurious actuation(s). Inspectors should review 3 or 4 of the most critical combinations.

(1) A maximum of two cables should be evaluated for cases where multiple cables may be damaged by the same fire. Multiple spurious actuations may be evaluated, depending on the number of conductors, and the circuit configuration.

(2) For cases involving direct current (DC) control circuits, consider the potential spurious operation due to failures of the control cables (even if the spurious operation requires two concurrent hot shorts of the proper polarity, e.g., plus-to-plus and minus-to-minus). Consider potential spurious actuations when the source and the target conductors are in two independent multiconductor cables.

(3) For cases involving decay heat removal (DHR) system isolation valves at high-pressure and low-pressure interfaces verify that the three-phase power cables to the valves (either thermoset or thermoplastic jacketed) are not vulnerable to three-phase proper polarity hot shorts.

2. Common Power Supply/Bus Concern. Verify, on a sarnple basis, that circuit breaker coordination and fuse protection have been analyzed, and are capable of protecting the power source of the designated redundant or alternative safe shutdown system/equipment.

g. Communications.

Issue Date: 12/24/09 7 IP 71111.05T Effective Date: 01/01/10

Verify through inspection of the contents of designated emergency storage lockers and review of emergency control station alternative shutdown procedures, that portable radio communications and/or fixed emergency communications systems are available, operable, and adequate for the performance of the designated activities. Assess the capability of the communication systems to support the operators in the conduct and coordination of their required actions (e.g., consider ambient noise levels, clarity of reception, reliability, and coverage patterns). If specific, issues arise relating to alternative or dedicated shutdown communications adequacy, then, observe a licensee conducted communications test in the subject plant area or areas.

Verify that communication equipment such as repeaters, transmitters etc. would not be affected by a fire.

h. Emergency Lighting.

Review emergency lighting provided, either in fixed or portable form, along access routes and egress routes, at control stations, plant parameter monitoring locations, and at manual operating stations:

1. If emergency lights are powered from a central battery or batteries, verify that the distribution system contains protective devices so that a fire in the area will not cause loss of emergency lighting in any unaffected area needed for safe shutdown operations.

2. Verify that battery power supplies are rated with at least an 8-hour capacity.

3. Verify the operability testing and maintenance of the lighting units follow licensee procedures and accepted industry practice.

4. Verify that sufficient illumination is provided to permit access to and verification of components for the monitoring of safe shutdown indications and/or the proper operation of SSD equipment.

5. Verify that emergency lighting unit batteries are being maintained consistent with the manufacturer's recommendations.

i. Cold Shutdown Repairs.

Verify that the licensee has repair procedures, equipment, and materials to accomplish repairs of components required for cold shutdown which might be damaged, that these components can be made operable, and that cold shutdown can be achieved within the required time frames. Verify that the repair equipment, components, tools, and materials (e.g., pre-cut cable connectors with prepared attachment lugs) are available and accessible on site.

j. Compensatory Measures.

Issue Date: 12/24/09 8 IP 71111.05T Effective Date: 01/01/10

1. General guidance. Verify that compensatory measures are in place for out-of-service, degraded, or inoperable fire protection and post-fire safe shutdown equipment, systems, or features (e.g. detection and suppression systems and equipment, passive fire barriers, or pumps, valves or electrical devices providing safe shutdown functions or capabilities). Short term compensatory measures should compensate for the degraded function or

• feature until appropriate corrective action can be taken. Review the licensee's effectiveness in returning the equipment to service in a reasonable period of time (typically days or weeks).

If the licensee meets the requirements in 10 CFR Part 50 Appendix R, Section III.G.2, then the use of operator manual actions to mitigate fire-induced operation or mal-operation to the second train may be credited without prior approval.

2. Manual Actions. The three acceptable methods that meet the requirement for maintaining one of the redundant trains in the same fire area free of fire damage are based on the combination of physical barriers, spatial separation, fire detection and automatic suppression systems. These methods are described in 10 CFR Part 50 Appendix R, Section III.G.2.

Licensee implemented manual actions to respond to potential maloperations that may result from the failure to meet this requirement do not correct the

\ underlying performance deficiency and therefore will not be accepted as final corrective action. However, the staff concluded that for an interim period, while appropriate corrective actions are implemented or while preparations are made by the licensee to submit exemptions or deviations, compensatory measures in the form of manual actions may be acceptable if the manual actions meet the criteria provided below.

If the inspectors determine that the manual actions cannot be reasonably accomplished and therefore implementation may lead to an unsafe plant condition, altemate compensatory measure(s) or temporary corrective action(s) must be implemented.

(a) Applicability. This guidance is provided for assessing manual actions implemented in conjunction with a licensee commitment to Section III.G.2.

Verify that the licensee is committed to meet the requirements of Section III.G.2. Determine whether the requirements are met with or without the use of manual actions. If manual actions are not invoked, this guidance is not applicable.

If manual actions were previously approved by the staff and an exemption or deviation has been issued, verify that the licensee continues to meet the terms of the exemption or deviation.

Issue Date: 12/24/09 9 IP 71111.05T Effective Date: 01/01/10

(b). Diagnostic Instrumentation. Verify that adequate diagnostfc instrumentation, unaffected by the postulated fire, is provided for the operator to detect the specific spurious operation that occurred. Some licensees may have protected only the circuits specified in Information Notice 84-09. Additional instrumentation may be needed to properly assess a spurious operation. Annunciators, indicating lights, pressure gages, and flow indicators are among the instruments typically not protected from the effects of a fire. Instrumentation should also be available to verify that the manual action accomplished the intended objective.

(c) Environmental Considerations. Evaluate environmental conditions the operators may encounter while traveling to the area where the manual action will be performed and within the area where the manual action will take place. The conditions to be verified may include the following:

(1) Radiation levels shall not exceed normal 10 CFR Part 20 limits.

(2) Emergency lighting is provided as required in Appendix R,Section III.J, or by the licensee's approved fire protection program.

(3) Temperature and humidity conditions are such that they do not affect the operator's ability to perform the manual action.

(4) Fire effects such as smoke and toxic gases do not affect the operator's ability to perform the manual action.

(d) Staffing. Evaluate licensee shift staffing to determine whether enough qualified personnel are available to perform the required manual actions and to safely operate the reactor.

(e) Communications. Verify that manual action coordination with other plant operations can be accomplished, and that communications capability is protected from effects of a postulated fire.

(f) Special Tools. Evaluate the need for special tools and verify that such tools are dedicated and readily available.

(g) Training. Verify that operator training on the manual actions and the associated procedure(s) is adequate and current.

(h) Accessibility. Evaluate the accessibility of tools and equipment. If special access equipment is needed (such as a ladder), verify the availability of the equipment. Verify that an operator can reach the required location without personal hazard.

(i) Procedures. Review procedural guidance to ensure that it is adequate Issue Date: 12/24/09 10 IP 71111.0ST Effective Date: 01/01/10

and given in an emergency procedure. Operators should not rely on having time to study normal plant procedures to find a method of operating plant equipment that is seldom used.

G) Verification and Validation. Determine whether the manual actions have been verified and validated by plant walkdowns using the current procedure. Ensure that the licensee has adequately evaluated the capability of oper~tors to' perform the manual action in the time available before the plant will be placed in an unrecoverable condition.

02.03 B.5.b Inspection Activities. Review one sample of the licensee's preparedness to handle large fires or explosions by reviewing one or more mitigating strategies. This review should verify that the licensee continues to meet the requirements of their B.5.b related license conditions and 10 CFR 50.54 (hh)(2) by determining that:

a. Procedures are being maintained and adequate.

b. Equipment is properly staged and is being maintained and tested.

c. Station personnel are knowledgeable and can implement the procedures.

02.04 Identification and Resolution of Problems. The team should verify that the licensee is identifying issues related to this inspection area at an appropriate threshold and entering them in the corrective action program. For a sample of selected issues documented in the corrective action program, verify that the corrective actions are appropriate. See Inspection Procedure 71152, "Identification and RJsolution of Problems," for additional guidance.

71111.05-03 INSPECTION GUIDANCE 03.01 Inspection Preparation.

a. Inspection Team. The team assigned to conduct the multi-disciplinary triennial fire protection inspection should include inspectors who are knowledgeable in the areas of reactor operations, electrical inspections, and fire protection.

1. Reactor Operations. The inspector knowledgeable in this area will assess the capability of reactor and balance-of-plant systems, equipment, operating personnel, and procedures to achieve and maintain post-fire safe shutdown and minimize the release of radioactivity to the environment in the event of' fire. Therefore, the inspection team leader will ensure that the inspector is knowledgeable regarding integrated plant operations, maintenance, testing, surveillance and quality assurance, reactor normal and off-normal operating procedures, and BWR and/or PWR nuclear and balance-of-plant systems design.

2. Electrical Inspections. The inspector knowledgeable in this area will identify electrical separation reqUirements for redundant train power, control, and instrumentation cables. The inspector will review altemative shutdown panel Issue Date: 12/24/09 11 IP 71111.05T Effective Date: 01/01/10

electrical isolation desi'gn to establish the' panel's' electrical independence from postulated fire areas. ThereforeJhe inspection team leader will ensure that the inspector is knowledgeable regarding reactor plant electrical and instrumentation and control (I&C) design and is familiar with industry ampacity derating standards.

3. Fire Protection. The inspector knowledgeable in this area will work with other team members in determining the effectiveness of the fire barriers and systems that establish the reactor plant's post-fire SSD configuration and maintain it free of fire damage. The inspector will determine whether suitable fire protection features (suppression, separation distance, fire barriers, etc.)

are provided for the separation of equipment and cables required to ensure plant safety. Therefore, the inspection team leader will ensure the inspector is knowledgeable regarding reactor plant fire protection systems, features and procedures.

4. B.5.b Mitigating Strategies. The inspector knowledgeable in this area will work with other team members to identify which alternative mitigating strategies should be reviewed. The inspector will determine if these strategies remain feasible. Therefore, the inspection team leader will ensure that the inspector is knowledgeable regarding B.5.b mitigating strategies.

b. Regulatory Requirements and Licensing Bases. The regulatory requirements and licensing bases against which post-fire safe shutdown capability is assessed are as follows:

1. Part 10 of the Code of Federal Regulations. 10 CFR 50.48(a), Fire Protection, requires each operating nuclear power plant to have a fire protection plan which satisfies the requirements of Criterion 3 of Appendix A to 10 Part 50. The NRC has identified that an acceptable plan is one that meets the requirements of Appendix R to 10 Part 50, or a plan that satisfies the guidance of standard review plan (SRP) Section 9.5-1.

2. Plants licensed before January 1, 1979. These plants are subject to the requirements of 10 CFR Part 50.48(a) and (b) and Appendix R to 10 CFR Part 50. Appendix R, Sections III.G, III.J, and 111.0 were backfit on plants licensed before January 1, 1979. Licensees were required to meet the separation requirements of Section III.G.2, the altemative or dedicated shutdown capability requirements of Sections III.G.3 and III.L, or to request an exemption in accordance with 10 CFR Part 50.12. Altemative or dedicated safe shutdown capabilities were required to be submitted to the Office of Nuclear Reactor Regulation (NRR) for review. NRR approvals are documented in SERs.

3. Plants licensed after January 1. 1979. These plants are subject to requirements as specified in the conditions oftheir facility operating license, in commitments made to the NRC, or in deviations exemptions or licensee amendments granted by the NRC. These requirements are generally similar Issue Date: 12/24/09 12 IP 71111.05T Effective Date: 01/01/10

to those in 10 CFR Part 50 Appendix R.

4. Changes to the fire protection program. The licensee may make changes to the approved fire protection program without prior approval by the Commission only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire. In addition the licensees may be required to retain the fire protection plan and each change to the plan as a record pursuant to paragraph 50.48. *

c. Licensee Notification and Information Gathering.

1. Licensee Notification Letter. The licensee should be notified of the triennial inspection in writing at least three months in advance of the onsite week.

The information gathering visit shall be conducted no fewer than three weeks in advance of the onsite inspection week. The letter should discuss the scope of the inspection, request an information-gathering visit to the licensee reactor site/engineering offices, discuss documentation and licensee personnel availability needs during the onsite inspection week, and request a pre-inspection conference call to discuss administrative matters and finalize inspection activity plans and schedules. A template for an NRC to licensee triennial fire protection baseline inspection notification letter is provided as Attachment 1. .

2. Information Gathering Site Visit. The inspection team shoulc( conduct a two to three day information gathering site visit. The purposes of the information gathering site visit are to (1) gather site-specific information important to inspection planning, and (2) conduct initial discussions with licensee.

representatives regarding administrative items and inspection activity plans and schedules. In advance of the information-gathering site visit, the team leader should provide the licensee with a list of information and documents that may be needed for the team to prepare for and conduct the triennial inspection, as well as a list of any planned requests for licensee conducted evolutions (e.g., emergency lighting tests, communication tests, fire drills, shutdown walkthroughs, etc.).

Prior to the inspection information gathering trip, the team leader should contact the regional (SRA) to obtain summary of plant specific fire risk insights (e.g., fire risk ranking of the rooms/plant fire areas, conditional core damage probabilities (CCDPs) for those rooms and areas, and transient sequences for these rooms). After considering the focus and result of past fire protection and post-fire safe shutdown inspections, the team should select three to five fire areas important to risk and conduct a walkdown of these areas prior to finalizing the sample selection and requesting documentation from the licensee.

After the information gathering site visit, the team leader should use the SRA developed fire risk insights, as well as technical input from the other team members, to develop an inspection plan addressing (for the selected three to Issue Date: 12/24/09 13 IP 71111.05T Effective Date: 01/01/10

five fire areas, zones, as applicable) post-fire SSD capability and the fire protection features for maintaining one success path of this capability free of fire damage.

3. Information Required/Preparation. The inspection team should gather sufficient information to become familiar with the following during the preparation period:

(a) The reactor plant's design, layout, and equipment configuration.

(b) The reactor plant's current post-fire safe shutdown licensing basis through review of 10 Part 50.48, 10 CFR Part 50 Appendix R (if applicable), NRC safety evaluation reports (SERs) on fire protection, the plant's operating license, updated final safety analysis report (UFSAR), and approved exemptions or deviations.

(c) The licensee's strategy and methodology, and derivative procedures, for accomplishing post-fire safe shutdown conditions. Among the sources of information are the updated final safety analysis report (UFSAR), the latest version of the fire hazards analysis (FHA), the latest version of the post-fire safe shutdown analysis (SSA), fire protection/post-fire safe-shutdown related changes that used 10 Part 50.59, 50.48(a) or other criteria, and Generic Letter 86-10 review documentation and modification packages, plant drawings, emergency/abnormal operating procedures, and the results of licensee internal audits (e.g., self assessments and quality assurance (QA) audits in the fire protection and post-fire safe shutdown areas).

(d) The historical record of plant-specific fire protection issues through review of plant-specific documents such as previous NRC inspection results, internal audits performed by the reactor licensee (e.g., self-assessments and quality assurance audits), corrective action system records, event notifications submitted in accordance with 10 CFR Part 50.72, and licensee event reports (LERs) submitted in accordance with 10 CFR 50.73.

(e) The safe shutdown systems and support systems credited by the licensee's analysis for each fire area, room, or zone for accomplishing of the required shutdown functions (e.g., reactivity control, reactor coolant makeup, reactor heat removal, and process monitoring and support functions) as necessary to comply with the SSD requirements of 10 CFR Part 50.48(a) and plant-specific licensing requirements. The shutdown logic for each area, room, or zone to be inspected must be thoroughly understood by the team members.

(f) The licensee's analytical approach for electrical circuit separation analyses, and the licensee's. methodology for identification and resolution of circuits of concern. The team's electrical review should Issue Date: 12/24/09 14 IP 71111.05T Effective Date: 01/01/10

include addressing the assumptions and boundary conditions used in the performance of the licensee's analyses.

03.02 Fire Protection Inspection Activities. For those fire protection structures, systems, and components installed to satisfy NRC requirements designed to NFPA codes and standards, the code edition in force at the time of the design and installation is the code of record to which the design is evaluated.

Deviations from the codes should be identified and justified in the UFSAR or FHA. A licensee may apply the equivalency concept in meeting the provisions of the NFPA codes and standards. When the licensee states that its design "meets the NFPA code(s)" or "meets the intent of the NFPA code(s)" and does not identify any deviations from such codes, the NRC expects that the design conforms to the codes and the design is subject to inspection against the NFPA codes. The "Authority Having Jurisdiction" as described in NFPA documents refers to the Director, Office of Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, or designee.

If the inspectors determine that the operator manual actions are not reasonably accomplishable and therefore implementation may not lead to a safe plant condition, the preliminary finding will be identified and entered into the Significance Determination Process (SOP), Inspection Manual Chapter IMC0609 Appendix F.

03.03 B.5.b Inspection Activities.

a. NEI 06-12, "B.5.b Phase 2 & 3 Submittal Guideline," the licensee's submittals, the NRC's SER, and the conforming license conditions (codified as 10 CFR 50.54(hh)(2)), available on the B.5.b Inspection Community of Practice website provide the bases and acceptance guidelines for B.5.b related equipment and mitigating strategies. Previous inspection reports should be referenced for commitments made by licensees to correct deficiencies identified during previous performance of this inspection or performance of TI 2515/171.

b. It is expected that most of the material that will be reviewed as part of this inspection effort will be sensitive unclassified non-safeguards information (SUNSI).

However, based on the scope of the inspection, it is not expected that any SUNS I material will need to be documented in the inspection report, and inspectors should preclude withholding information from public inspection reports to the maximum extent practical. In the event that an inspection does require documentation of such information, guidance on how it should be accomplished is provided in IMC 0612. Additional guidance regarding SUNSI is available on the NRC internal website (http://www.internal.nrc.gov/sunsi).

03.04 Identification and Resolution of Problems. No specific guidance is provided.

71111.05-04 RESOURCE ESTIMATE The resource to perform this inspection procedure is estimated to be 218 hours0.00252 days <br />0.0606 hours <br />3.604497e-4 weeks <br />8.2949e-5 months <br /> every 3 Issue Date: 12/24/09 15 IP 71111.05T Effective Date: 01/01/10

years for the triennial inspection regardless of the number of reactor units at ttie site.

71111.05-05 PROCEDURE COMPLETION Inspection of the minimum sample size will constitute completion of this procedure in the Reactor Programs System (RPS).

The minimum sample size for fire protection inspection activities is defined as 3 samples (inspection of three fire areas) regardless of the number of reactor units at that site.

The minimum sample size for B.5.b inspection activities is defined as 1 sample regardless of the number of reactor units at that site.

71111.05-06 REFERENCES NOTE: Some references contain hyperlinks to the specific document. These hyperlinks should be used with caution (the linked document should be verified to be the current version prior to use).

Inspection Manual Chapter 0609, Appendix F, "Fire Protection Significance Determination Process" Inspection Procedure 71152, "Identification and Resolution of Problems" Information Notice 97-48, "Inadequate or Inappropriate Interim Fire Protection Compensatory Measures" Individual Plant Examination of Externally Initiated Events (IPEEE)

Regulatorv Guide 1.189, "Fire Protection for Nuclear Power Plants" Regulatorv Issue Summary 2004-03, Rev 1, "Risk-Informed Approach for Post-Fire Safe-Shutdown Circuit Inspections" Regulatory Issue Summary 2005-07, "Compensatory Measures to Satisfy the Fire Protection Program Requirements" Regulatory Issue Summary 2005-20, "Revision to Guidance Formerly Contained in NRC Generic Letter 91-18, 'Information to Licensees Regarding Two NRC Inspection Manual Sections on Resolution of Degraded and Nonconforming Conditions and on Operability" Regulatory Issue Summary 2005-30, "Clarification of Post-Fire Safe-Shutdown Circuit Regulatory Requirements" Temporary Instruction 2515/171, "Verification of Site Specific Implementation of B.5.b Phase 2 & 3 Mitigating Strategies" Issue Date: 12/24/09 16 IP 71111.05T Effective Date: 01/01/10

NEI 99-04, "Guidelines for Managing NRC Commitments" (ML003680088)

NRR Office Instruction 105, "Managing Regulatory Commitments Made by Licensees to the NRC" NEI 06-12, Rev 2, "B.5.b Phase 2 & 3 Submittal Guideline" 8'.5.b Inspection Community of Practice WCAP 16800-NP, Revision 0, "Insights for Operating Steam Generators to Minimize RCS Inventory Loss Following a Loss of All AC and DC Power" (ML091410184)

\

Issue Date: 12/24/09 17 IP 71111.05T Effective Date: 01/01/10

ATTACHMENT 1 .

Mr. President Licensee Nuclear Department Licensee Corporation or Company Address

SUBJECT:

SELECTED NUCLEAR POWER STATION, UNITS 1 AND 2 - NOTIFICATION OF CONDUCT OF A TRIENNIAL FIRE PROTECTION BASELINE INSPECTION

Dear Mr. :

The purpose of this letter is to notify you that the U.S. Nuclear Regulatory Commission (NRC) Region # staff will conduct a triennial fire protection baseline inspection at Selected Nuclear Power Station, Units 1 and 2 in Month, 20##. The inspection team will be lead by First Last, a fire protection specialist from the NRC Region # Office. The team will be composed of personnel from NRC Region #, and Contracted National Laboratory. The inspection will be conducted in accordance with IP 71111.05, the NRC's baseline fire protection inspection procedure.

The schedule for the inspection is as follows:

• Information gathering visit - Dates [Note - this date is pre-coordinated with the licensee]

• Week of onsite inspection - Dates.

The purposes of the information gathering visit are to obtain information and documentation needed to support the inspection, to become familiar with the Selected Nuclear Power Station, Units 1 and 2 fire protection programs, fire protection features, post-fire safe shutdown capabilities and plant layout, mitigating strategies to address Section B.5.b of the Interim Compensatory Measures Order, EA-02-026, of February 25, 2002/10 CFR 50.54(hh)(2); and, as necessary, obtain plant specific site access training and badging for unescorted site access. A list of the types of documents the team may be interested in reviewing, and possibly obtaining, are listed in Enclosures 1 and 2.

During the information gathering visit, the team will also discuss the following inspection support administrative details: office space size and location; specific documents requested to be made available to the team in their office spaces; arrangements for reactor site access (including radiation protection training, security, safety and fitness for duty requirements); and the availability of knowledgeable plant engineering and licensing organization personnel to serve as points of contact during the inspection.

We request that during the onsite inspection week you ensure that copies of analyses, evaluations or documentation regarding the implementation and maintenance of the Selected Nuclear Generating Station, Units 1 and 2 fire protection program, including post-Issue Date: 12/24/09 Att1-1 71111.05T Effective Date: 01/01/10

fire safe shutdown capability, be readily accessible to the team for their review. Of specific interest for the fire protection portion of the inspection are those documents which establish that your fire protection program satisfies NRC regulatory requirements and conforms to applicable NRC and industry fire protection guidance. For the B.5.b portion of the inspection, those documents implementing your mitigating strategies and demonstrating the management of your commitments for the strategies are of specific interest. Also, personnel should be available at the site during the inspection who are knowledgeable regarding those plant systems requirE!d to achieve and maintain safe shutdown conditions from inside and outside the control room (including the electrical aspects of the relevant post-fire safe shutdown analyses), reactor plant fire protection systems and features, and the Selected Nuclear Power Station fire protection program and its implementation.

This letter does not contain new or amended information collection requirements subject to the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.). Existing information collection requirements were approved by the Office of Management and Budget, control number 3150-0011. The NRC may not conduct or sponsor, and a person is not required to respond to, a request for information or an information collection requirement unless the requesting document displays a currently valid Office of Management and Budget control number.

Your cooperation and support during this inspection will be appreciated. If you have questions concerning this inspection, or the inspection team's information or logistical needs, please contact First Last, the team leader, in the Region # Office at ###-###-####.

Sinc~rely, Docket Nos.: 50-###

and 50-###

Enclosure:

As stated (1)

Issue Date: 12/24/09 Att1-2 71111.05T Effective Date: 01/01/10

ENCLOSURE 1 Reactor Fire Protection Program Supporting Documentation

[Note: This is a broad list of the documents the NRC inspection team may be interested in reviewing, and possibly obtaining, during the information gathering site visit.]

1. The current version of the Fire Protection Program and Fire Hazards Analysis.

2. Current versions of the fire protection program implementing procedures (e.g.,

administrative controls, surveillance testing, fire brigade).

3. Fire brigade training program and pre-fire plans.

4. Post-fire safe shutdown systems and separation analysis.

5. Post-fire alternative shutdown analysis.

6. Piping and instrumentation (flow) diagrams showing the components used to achieve and maintain hot standby and cold shutdown for fires outside the control room and those components used for those areas requiring alternative shutdown capability.

7. Plant layout and equipment drawings which identify the physical plant locations of hot standby and cold shutdown equipment.

8. Plant layout drawings which identify plant fire area delineation, areas protected by automatic fire suppression and detection, and the locations of fire protection equipment.

9. Plant layout drawings which identify the general location of the post-fire emergency lighting units.

10. Plant operating procedures which would be used and describe shutdown from inside the control room with a postulated fire occurring in any plant area outside the control room, procedures which would be used to implement alternative shutdown capability in the event of a fire in either the control or cable spreading room.

11. Maintenance and surveillance testing procedures for alternative shutdown capability and fire barriers, detectors, pumps and suppression systems.

12. Maintenance procedures which routinely verify fuse breaker coordination in accordance with the post-fire safe shutdown coordination analysis.

Issue Date: 12/24/09 E1-1 71111.05T Effective Date: 01/01/10

13. A sample of significant fire protection and post-fire safe shutdown related design change packages and Generic Letter 86-10 evaluations.

14. The reactor plant's IPEEE, results of any post-IPEEE reviews, and listings of actions taken/plant modifications conducted in response to IPEEE information.

15. Temporary modification procedures. *

16. Organization charts of site personnel down to the level of fire protection staff personnel.

17. If applicable, layout/arrangement drawings of potential reactor coolant/recirculation pump lube oil system leakage points and associated lube oil collection systems.

18. A listing of the SERs which form the licensing basis for the reactor plant's post-fire safe shutdown configuration.

19. Procedureslinstructions that control the configuration of the reactor plant's fire protection program, features, and post-fire safe shutdown methodology and system design.

20. A list of applicable codes and standards related to the design of plant fire protection features and evaluations of code deviations.

21. Procedures/instructions that govern the implementation of plant modifications, maintenance, and special operations, and their impact on fire protection.

22. The three most recent fire protection QA audits and/or fire protection self-assessments.

23. Recent QA surveillances of fire protection activities.

24. A listing of open and closed fire protection condition reports (problem reports/NCRs/EARs/problem identification and resolution reports).

25. Listing of plant fire protection licensing basis documents.

26. A listing of the NFPA code versions committed to (NFPA codes of record).

28. A listing of plant deviations from code commitments.

29. Actual copies of Generic Letter 86-10 evaluations.

Issue Date: 12/24/09 E1-2 71111.05T Effective Date: 01/01/10

ENCLOSURE 2 Mitigating Strategies Supporting Documentation

[Note: This is a broad list of the documents the NRC inspection team may be interested in reviewing, and possibly obtaining, during the information gathering site visit.]

1. A list of all modifications to regulatory commitments made to meet the requirements of Section B.S.b of the ICM Order, EA-02-026, dated February 2S, 2002, the subsequently imposed license conditions, and 10 CFR SO.S4(hh)(2).

2. Copies of procedures/guidelines that were revised or generated to implement the mitigation strategies. These could be extensive damage mitigation guidelines (EDMGs), severe accident management guidelines (SAMGs), emergency operating procedures (EOPs), abnormal operating procedures (AOPs), etc.

3. A matrix that shows the correlation between the mitigation strategies identified in Nuclear Energy Institute 06-12 and the site-specific procedures or guidelines that are used to implement each strategy.

4. Engineering evaluations/calculations that were used to verify engineering bases for the mitigation strategies.

S. Piping and instrumentation diagram (P&ID) or simplified flow diagrams for systems relied upon in the mitigation strategies. These could be the type used for training.

6. A modification package or simplified drawings/descriptions of modifications that were made to plant systems to implement the mitigation strategies.

7. Copies of procedures used to inventory equipment (hoses, fittings, pumps, etc.)

required to be used to implement the mitigation strategies.

8. A list of B.S.b strategies, if any, which have implementing details that differ from that documented in the submitfals and the safety evaluation report.

9. A copy of site general arrangement drawing(s) that show the majority of buildings/areas referenced in B.S.b documents.

10. Training recordsl training matrix/lesson plans related to B.S.b.

11. Copies of Memoranda of Understanding (MOUs) (e.g., with local fire departments) required to implement any mitigating strategies.

END Issue Date: 12/24/09 E2-1 71111.0ST Effective Date: 01/01/10

13. A sample of significant fire protection and post-fire safe shutdown related design change packages and Generic Letter 86-10 evaluations.

14. The reactor plant's IPEEE, results of any post-IPEEE reviews, and listings of actions taken/plant modifications conducted in response to IPEEE information.

15. Temporary modification procedures.

16. Organization charts of site personnel down to the level of fire protection staff personnel.

17. If applicable, layout/arrangement drawings of potential reactor coolant/recirculation pump lube oil system leakage points and associated lube oil collection systems.

18. A listing of the SERs which form the licensing basis for the reactor plant's post-fire safe shutdown configuration.

19. Procedures/instructions that control the configuration of the reactor plant's fire protection program, features, and post-fire safe shutdown methodology and system design.

20. A list of applicable codes and standards related to the design of plant fire protection features and evaluations of code deviations.

21. Procedures/instructiCfls that govem the implementation of plant modifications, maintenance, and special operations, and their impact on fire protection.

22. The three most recent fire protection QA audits and/or fire protection self-assessments.

23. Recent QA surveillances of fire protection activities.

24. A listing of open and closed fire protection condition reports (problem reports/NCRs/EARs/problem identification and resolution reports).

25. Listing of plant fire protection licensing basis documents.

26. A listing of the NFPA code versions committed to (NFPA codes of record).

28. A listing of plant deviations from code commitments.

29. Actual copies of Gener'lc Letter 86-10 evaluations.

Issue Date: 12/24/09 E1-2 71111.05T Effective Date: 01/01/10

ATTACHMENT 2 Revision History For Inspection Procedure IP 71111.0ST Commitment Issue Date Description of Change Training Training Comment Tracking N~eded Completion Resolution Number Date Accession Number N/A 04/21/06 Previous History Review N/A N/A N/A N/A 03/06/03 Provide inspection guidance to evaluate No N/A NA CN 03-007 licensee manual actions which have been incorporated into the procedure as Enclosure N/A 12/01/04 This revised triennial fire protection Yes 11/04 NA CN 04-027 inspection procedure includes inspection guidance for identifying circuits that could preventthe plant from achieving and maintaining hot shutdown condition after a fire. Inspection of these circuits was suspended in 2000, pending the conduct of fire tests and the assessment of the results in order to gain risk insights into the phenomena of fire-induced electrical cable failures. The inspection guidance is designed to help the inspectors identify categories of circuit configurations most likely to be impacted by fire potentially affecting the capability of the operators to bring the plant to a safe shutdown condition.

Issue Date: 12/24/09 Att2-1 71111.0ST Effective Date: 01/01/10

N/A 04/21/06 This revision reflects the withdrawal of the No NA NA Manual Action rule. Manual actions will not be acceptable as alternatives to the existing requirements of 10 CFR Part 50.48(b) unless the licensee submits an exemption/deviation request. However. the use of manual actions will continue to be acceptable as compensatory measures. To that effect this procedure continues to provide guidance to the inspectors to assess the viability of manual actions as compensatory measures.

NA 12/24/09 This revision incorporates the B.5.b No NA ML093410056 CN 09-032 inspection attributes (previously inspected via TI 2515/171) to this procedure so that the inspection will be performed by specifically trained DRS staff on a triennial basis consistent with the relative risk and safety significance of this issue. Additional resource estimate for revised procedure is 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> (triennially) based on experience with the B.5.b Tis. This revision also includes incorporation of ROP Feedback Form 1344 (inspector knowledge requirements). 1345 (duplication of guidance) and 1383 (staffing and scope of information gathering trip). The format has also been revised to meet the requirements of IMC 0040.

Issue Date: 12/24/09 Att2-2 71111.05T Effective Date: 01/01/10

ATTACHMENT 71111.0SAQ INSPECTABLE AREA: Fire Protection (Annual/Quarterly)

CORNERSTONES: Initiating Events Mitigating Systems I EFFECTIVE DATE: January 1, 2010 INSPECTION BASES: Fire can be a significant contributor to reactor plant risk. In many cases, the risk posed by fires is comparable to or exceeds the risk from internal events. The fire protection program shall extend the concept of defense in depth (DID) to fire protection in plant areas important to safety by:

(1) preventing fires from starting, (2) rapidly detecting, controlling, and extinguishing those fires that do occur, and (3) providing protection for structures, systems, and components important to safety so that a fire that is not promptly extinguished by fire suppression activities will not prevent the safe shutdown of the reactor plant.

LEVEL OF EFFORT: Quarterly Inspection: The resident inspector will perform a DID walkdown of four to six plant areas important to safety (on a plant specific basis) each calendar quarter per Section 02.01.

Annual Inspection: Each year, the resident inspector will evaluate the fire brigade performance by observing selected fire drills. Fire brigade drills may be announced or unannounced.

Observation of the fire brigade response to an actual fire can be considered as part of the evaluation.

71111.05AQ-01 INSPECTION OBJECTIVES 01.01 The inspectors will ,evaluate the licensee's fire protection program for operational status, and material condition and verify the adequacy of:

• . controls for combustibles and ignition sources within the plant;

• fire detection and suppression capability;

• material condition of passive fire protection features;

• compensatory measures in place for out-of-service, degraded or inoperable fire Issue Date: 11/16109 1 71111.05AQ Effective Date: 01/01/10 Enclosure 4

protection equipment, systems or features; and

• procedures, equipment, fire barriers, and systems so that the post-fire capability to safely shut down the plant is ensured.

01.02 To assess the performance of the fire brigade.

71111.0SAQ-02 INSPECTION REQUIREMENTS 02.01 Quarterly Inspection. The inspector should review the fire plan for the area selected against the fire protection program defined hazards and DID features to verify that the fire plan is adequate. The fire plan should then be used as a tool in evaluating the attributes below for the selected fire areas. For the areas selected evaluate the following:

a. Control of Transient Combustibles and Ignition Sources. Verify the following:

1. Transient combustible materials and location of transient combustible materials are being controlled in accordance with the licensee's administrative control procedures and the licensee's fire PRA analysis (special focus should be made on transient combustibles located in the vicinity of ignition sources and safe shutdown cables and equipment).

2. Hot work, welding, cutting, heat treating, grinding, brazing, flame or plasma arc cutting, or arc gouging is being done in accordance with the licensee's administrative control procedures.

b. Fire Detection Systems.

Verify the physical condition of the fire detection devices and note any that show physical damage, blockage or potential interference with functionality (see Compensatory Measures section below).

c. Water-based Fire Suppression Systems. Verify the following:

1. Sprinkler heads and nozzles are not obstructed by major overhead equipment (e.g., ventilation ducts), or temporary scaffolding, are not damaged or painted, and are installed in the proper orientation (e.g., upright, pendent, or sidewall). Verify that floor drains in areas protected by sprinkler/water spray systems are open/unobstructed and that drainage is directed to areas that will not be adversely affected by the runoff.

2. Water supply control valves to the system are open and the fire water supply and pumping capability is operable and capable of supplying the water supply demand of the system (Verify through visual observation or surveillance record). Verify that trim valves on alarm check valves and deluge valves are aligned to the correct position for automatic operation.

3. Material conditions such as mechanical damage, painted sprinkler heads, Issue Date: 11/16/09 2 71111.0SAQ Effective Date: 01/01/10

corrosion, etc. will not affect performance of the system.

d. Gaseous Fire Suppression Systems. Verify the following:

1. Gaseous suppression system (e.g. Halon, C02, FM200, Inergen, etc.)

nozzles are not obstructed or blocked by plant equipment such that gas dispersal would be significantly impeded .

2. Suppression agent charge pressure is within the normal band, extinguishing agent supply valves are open, and the system is in the appropriate mode.

Verify that system actuation panels are powered on and that the panels are free of trouble indications or standing alarms. Look for longstanding uncorrected equipment problems.

3. Dampers/doors are unobstructed so that they will be permitted to close automatically upon actuation of the gaseous system. Observe any material condition that may affect the performance of the system, such as mechanical damage to doors or dampers, open penetrations (open floor drains may preclude proper gaseous concentration following actuation). In rooms protected with a total flooding gaseous suppression agent, verify that all egress doors are properly labeled to wam the occupants of the danger of a system discharge, and that egress door latches fully engage such that design concentrations will be maintained

4. Roon\ penetration seals are sealed and in good condition to prevent airflow and to prevent loss of gaseous suppression agent following discharge.

5. Material conditions such as mechanical damage, corrosion, damage to doors or dampers, open penetrations, or nozzles blocked by plant equipment that may affect performance of the system.

e. Manual Firefighting Equipment and Capability. Verify the following:

1. Portable fire extinguishers are provided at their designated locations in or near the area being inspected, access to the fire extinguishers is unobstructed by plant equipment or other work related activities, and appropriate for the class of fire hazard.

2. The general condition of fire extinguishers is satisfactory (e.g., pressure gauge reads in the acceptable range, nozzles are clear and unobstructed, charge test records indicate testing within the normal periodicity).

3. Fire hoses are installed at their designated locations and the general condition of hoses and hose stations is satisfactory (e.g., no holes in or chafing of the hose, nozzles not mechanically damaged and not obstructed, valve hand wheels in place), and access to the hose stations is unobstructed.

Issue Date: 11/16/09 3 71111.05AQ Effective Date: 01/01/10

4. Water supply control valves to the standpipe system are open and the fire water supply and pumping capability is operable and capable of supplying the water flow and pressure demand.

5. Access to manual actuators for fixed suppression systems (e.g. gaseous systems, dry water systems) is unobstructed by plant equipment or work-related activities.

f. Passive Fire Protection Features. Verify the following:

1. Electrical raceway fire barrier systems such as cable tray and conduit (including associated support system) fire wraps, or blanket materials are in good condition with no cracks, gouges, or holes in the barrier material, and no gaps in the material at joints or seams, and that banding, wire tie, and other fastener pattern and spacing appears appropriate.

2. Fire doors self-close without gapping (e.g. due to fire door damage from previous obstructions), and that the door latching hardware functions securely.

3. Ventilation system fire damper's material conditions, including fusible links where applicable, are adequate to ensure unobstructed operability. For those dampers which can not be readily observed in the selected plant areas, review the licensee's surveillance efforts directed towards verifying the continuing operability of ventilation fire dampers.

4. Structural steel fire proofing, such as fibrous or concrete encapsulation, is installed in such a way that the structural steel is uniformly covered (no bare areas).

5. Fire barrier and fire area/room/zone electrical and piping penetration seals are not missing from locations where they are needed to complete a fire barrier wall, and determine that seals appear to be properly installed and in good condition.

6. Reactor coolant pump oil collection systems designed to collect oil leakage and spray from all potential reactor coolant pump oil system leakage points have been installed and properly maintained (Time permitting, the actual installation should be verified during outages after work on the pumps has been completed). Visually inspect the oil collection pans and spray shields to verify they are collecting all oil leakage.

g. Compensatory Measures and Fire Watch. Verify the following:

1. Compensatory measures are put in place by the licensee for out-of-service, degraded or inoperable fire protection equipment, systems or features (e.g.

detection and suppression systems and equipment, passive fire barrier Issue Date: 11/16/09 4 71111.05AQ Effective Date: 01/01/10

features, or safe shutdown functions or capabilities). Fire watch is often the compensatory measure of choice for a large variety of fire protection malfunctions and deficiencies. Assure that the fire watch or other compensatory measure is commensurate with the significance of the deficiency.

2. Verify that assigned fire watches are being completed. This can be done by checking a completed fire watch log forthe time and individual making \he completed tour, then checking it against security key card entry records.

Another method could be to wait in an area requiring a fire watch inspection to see if the individual performing the fire watch comes through the area.

This later method could be combined with inspecting that area as a fire area sample

3. Licensee's plans for permanent corrective actions including effectiveness in returning the equipment to service in a reasonable period of time.

4. For plants that have transitioned to NFPA 805 inspectors should do sample walkdowns of the revised procedures for assessing the feasibility of the manual actions that the licensees are implementing as part of their corrective actions.

02.02 Annual Inspection. The annual inspection evaluates the licensee's fire brigade performance. While the evaluation is an annual proces~, observation and evaluation of all the important drill activities as part of single drill may not be effectively accomplished.

Therefore, inspectors may need to observe the conduct of several fire brigade drill segments (announced and unannounced) through the year to be able to formulate an appropriate assessment for the period. The licensee's fire brigade capabili\y to meet 10 CFR 50, Appendix R, Section III H and I requirements for training, dedicated size and membership, equipment, etc., can be verified independent of drills (Appendix R requirements may not apply to all sites). This review is conducted to ensure the capability of the fire brigade members, the leadership abili\y of the brigade leader, use of turnout gear and fire-fighting equipment, and the effectiveness of the team operation.

As part of the observation of fire brigade drills, verify that the fire brigade considers the following aspects when it responds and conducts their fire fighting activities:

a. The specified number of individuals assigned to the fire brigade response including the fire brigade leader. Minimum of five dedicated members with no ancillary duties.

b. Each member sets out his/her designated protectivE;! clothing and turnout gear, and properly dons the gear. Identify the required gear and verify availability of correct sizes.

c. Self-contained breathing apparatus (SCBA) are available and are properly worn and used. Verify that bunker gear, including the complete SCBA, was completely Issue Date: 11/16/09 5 71111.05AQ Effective Date: 01/01/10

donned before entering the fire scene. Evaluate the SCBA program including storage, training, expectations for use, and maintenance. Findings in this area should be assessed for significance using IMC 0609 Appendix B, Emergency Preparedness SDP.

d. Control room personnel follows procedure for verification of the fire and initiation of response, including identification of fire location, dispatching fire brigade, and sounding alarms. Emergency action levels are declared and notifications are made in accordance with NUREG 0654 and 10 CFR 50.

e. Fire brigade leader exhibits command of the fire brigade and has a copy of the pre-fire plans or strategy. Manager in charge of the response, for example, the shift supervisor or SRO (not the fire brigade leader), has access to pre-fire plans or strategy and applicable procedures.

f. Starting at the muster area fire brigade leader maintains control. Members are briefed, discuss plan of attack, receive individual assignments, complete communications checks, and generally get ready to combat the fire. Plan of attack discussion should be consistent with the pre-fire plans or strategies and include potential hazards in the fire area.

g. Fire brigade arrives at the fire scene in a timely manner, taking the appropriate access route specified in the strategies and procedures. For fire drills conducted in the radiation control areas, the specified most direct route may not be followed by the brigade.

Control/command is set up near the location of the fire after assessing the fire, and communications are established with the control room and fire brigade members.

Radio communications between the command post, control room, and plant operators and among fire brigade members remain efficient and effective for the duration of the drill.

h. Fire hose lines are capable of reaching all necessary fire hazard locations, the lines are laid out without flow constrictions and the hose is simulated as being charged with water.

i. The fire area of concem is entered in a controlled manner following the principle of "two-in/two-out" (two fire brigade members enter while two remain outside the area of concern). Additionally, the fire brigade members stay low to the floor and feel the door for heat prior to entry into the fire area of concern.

j. The fire brigade brings sufficient fire-fighting equipment to the scene to properly perform its fire-fighting duties.

k. Members of the fire brigade check for fire victims and propagation into other plant areas.

Issue Date: 11/16/09 6 71111.05AQ Effective Date: 01/01/10

I. Effective smoke removal operations are simulated in accordance with pre-fire plans and strategies by aligning ventilation in the fire area or by placing smoke removal units at the proper doors. Areas protected by gaseous suppression systems should not be ventilated before the brigade confirms that the fire is extinguished. If the simulation of smoke removal is not part of the drill verify availability and condition of such equipment (e.g. fans, hoses, etc.).

m. The fire-fighting pre-fire plan strategies were utilized. *

n. The licensee's drill scenario was followed, and the acceptance criteria for the drill objectives were met.

o. The licensee performs a post-drill critique to discuss any failures and weaknesses associated with the fire drill performance. Training and other improvement needs are identified.

p. At the conclusion of the drill, all fire fighting equipment is retumed to a condition of readiness to respond to an actual fire.

02.03 Identification and Resolution of Problems. During quarterly and annual resident inspections, verify that the licensee is identifying issues related to this inspection area at an appropriate threshold and entering them into the corrective action program. For a sample of selected issues documented in the corrective action program, verify that the corrective actions are appropriate. See Inspection Procedure 71152, "Identification and Resolution of Problems," for additional guidance. \

71111.05AQ-03 INSPECTION GUIDANCE General Guidance.

For those fire protection structures, systems, and components installed to satisfy NRC requirements, designed to NFPA codes and standards, that the code edition in force at the time of the design and installation is the code of record to which the design is evaluated.

Deviations from the codes should be identified and justified in the FSAR or FHA. A licensee may apply the equivalency concept in meeting the provisions of the NFPA codes and standards. When the licensee states that its design "meets the NFPA code(s)" or "meets the intent of the NFPA code(s)" and does not identify any deviations from such codes, the NRC expects that the design conforms to the codes and the design is SUbject to inspection against the NFPA codes.

The "Authority Having Jurisdiction" as described in NFPA documents refers to the Director, Office of Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, or designee, consistent with the authority specified in 10 CFR 1.43.

The main focus of the quarterly inspections is on the material condition and operational Issue Date: 11/16/09 7 71111.05AQ Effective Date:. 01/01/10

status of fire detection and suppression systems and equipment, and fire barriers used to prevent fire damage or fire propagation.

The resident inspectors may risk-inform the focus of their walkdowns by following the guidance provided below:

• The selection of areas to be inspected is based on risk insights from a senior reactor analyst (SRA), NRC Significance Process (SDP) worksheets, or the plant specific PRA. Similar information may be readily available from the past triennial fire protection inspection reports (IP71111.05T) as well.

• The selection of areas to be inspected factors in the plant configuration. In this regard, IP71111.04 "Equipment Selection" and IMC 2515, Appendix D provides insights on areas that are likely to result in risk-significant findings.

• For example, if train A of a safety system is out of service, then any finding in fire areas containing components of cables of train B are likely to result in potentially risk significant findings. Also, if the fire detection or suppression systems of a particular fire area are degraded or out of service, then findings in areas that house cables or components of the redundant train are likely to result in potentially risk-significant findings.

• For plants that have adopted a risk-informed, performance-based Fire Protection Program in accordance with 10CFR 50.48(c) and NFPA 805, the inspectors may use information developed by the licensee for understanding the risk insights for various plant areas.

Specific Guidance.

03.01 Quarterly Inspection. The resident inspector should not attempt to address all plant areas during each inspection. The routine plant DID walkdown should focus on four to six plant areas important to safety. The resident inspector should note transient combustibles and ignition sources (and compare these with the limits provided in licensee's administrative procedures). The resident inspector should also note the material condition and operational status (rather than the design) of fire detection and suppression systems, and fire barriers used to prevent fire damage or fire propagation.

The fire plan should define the hazards and fire protection DID features to assist the inspector in determining whether the attributes of the fire area are within the limits of the licensing basis defined in the fire protection program. The required content ofthe fire plans will be defined in the fire protection program and will include information such as fire hazards, locations of hose stations and extinguishers, locations of sprinkler isolation valves, important equipment in the area, etc. The plan can be a great help in distinguishing what combustibles are transient combustibles (if it is not on the plan, it is probably transient). The accuracy of the fire plan is important because it will be an important tool in providing information and guidance to the fire brigade team leader in determining the most likely location of the fire in the fire area and the best strategy for approaching the fire.

Issue Date: 11/16/09 8 71111.05AQ Effective Date: 01/01/10

03.02 Annual Inspection. Follow the guidance provided in section 02.02 of this procedure.

03.03 Identification and Resolution of Problems. No specific guidance provided.

71111.05AQ-04 RESOURCE ESTIMATE The resources to perform this inspection procedure is estimated to be, on average, 35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br /> per year for quarterly and annual inspections including time allocated for annual observation of a fire drill.

71111.05AQ-05 COMPLETION STATUS Inspection of the minimum sample size will constitute completion of this procedure in the Reactor Programs System (RPS). That minimum sample size will consist of one sample representing observation of selected fire drills in accordance with Section 02.02, and 16 samples per year representing tours of plant areas important to safety in accordance with Section 02.01.

END Issue Date: 11/16/09 9 71111.05AQ Effective Date: 01/01/10

Attachment 1 Revision History For IP 71111.05AQ Commitment Issue Date Description of Change Training Training Comment Resolution Tracking Needed Completion Accession Number Number Date N/A 08/31/06 Researched commitments back four N/A N/A N/A years - none found.

N/A 07/07/05 Updated guidance to assess fire No N/A None brigade performance.

N/A 09/05/06 Added "Completion Status" No N/A None CN 06-022 identifying a sample size of 24.

N/A 01/31/08 2007 ROP Re-alignment reduced the No N/A N/A CN 08-005 sample size to 16 and resource hours to 35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br />. Replace "tour" with "perform a defense-in-depth (DID) walkdown." (ROPFF 1155)

NA 11/16/09 Updated the procedure to No N/A ML092780063 CN 09-027 incorporate specific elements of NFPA-805.

Issue Date: 11/16/09 Att 1-1 71111.05AQ Effective Date: 01/01/10

August 27, 2007 Mr. Christopher M. Crane President and CNO Exelon Nuclear Exelon Generation Company, LLC 200 Exelon Way Kennett Square, PA 19348

SUBJECT:

LIMERICK GENERATING STATION - NRC TRIENNIAL FIRE PROTECTION INSPECTION REPORT 05000352/2007006 AND 05000353/2007006

Dear Mr. Crane:

On August 3, 2007, the NRC completed a triennial fire protection team inspection at your Limerick Generating Station. The enclosed report documents the inspection results which were discussed at an exit meeting on August 9,2007, with Mr. C. Mudrick and other members of your staff.

The inspection examined activities conducted under yout license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

This report documents one NRC-identified finding of very low safety significance (Green). The finding was determined to involve a violation of NRC requirements. However, because of the very low safety significance and because it was entered into your corrective action program, the NRC is treating this finding as a non-cited violation (NCV) consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest the NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Limerick Generating Station.

Enclosure 5

C. Crane 2 In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/ADAMS.html(the Public Electronic Reading Room).

Sincerely, IRAJ John F. Rogge, Chief Engineering Branch 3 Division of Reactor Safety Docket Nos. 50-352, 50-353 License Nos. NPF-39, NPF-85

Enclosure:

NRC Inspection Report 05000352/2007006 and 05000353/2007006

C. Crane 2 In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/ADAMS.html (the Public Electronic Reading Room).

• Sincerely, IRAJ John F. Rogge, Chief Engineering Branch 3 Division of Reactor Safety Docket No. 50-352, 50-353 License Nos. NPF-39, NPF-85

Enclosure:

NRC Inspection Report 05000352/2007006 and 05000353/2007006 1

SUNSI Review Complete: _ _->J!£F:.rR'--_ _ _ (Reviewer's Initials)

ADAMS#ML072400443 DOCUMENT NAME: C:IFileNetIML072400443.wpd After declaring this document "An Official Agency Record" it will be released to the Public.

To receive a CODV of this document, indicate in the box: "C" = CODY without attachment/enclosure liE" - CODY with attachment/enclosure "N" ;:: No copy OFFICE RIIDRS I RIIDRS I RIIDRP I RIIDRS I I NAME KYouno/KY WCooklWAC PKrohn/PGK JRoaae/JFR .

DATE 08/15107 08/15/07 08/17107 08/27107 OFFICE I I I I I NAME DATE I I I OFFICIAL RECORD COPY I I I Enclosure

C. Crane 3 cc w/encl:

Chief Operating Officer, Exelon Generation Company, LLC Site Vice President - Limerick Generating Station Plant Manager, Limerick Generating Station Regulatory Assurance Manager - Limerick Senior Vice President - Mid-Atlantic Operations Senior Vice President - Operations Support Vice President - Licensing and Regulatory Affairs Director - Licensing and Regulatory Affairs, Exelon Generation Company, LLC Manager, Licensing - Limerick Generating Station Vice President, General Counsel and Secretary Correspondence Control Desk Director, Bureau of Radiation Protection, PA Department of Environmental Protection J. Johnsrud, National Energy Committee, Sierra Club Chairman, Board of Supervisors of Limerick Township Enclosure

C. Crane 4 Distribution w/encl: (via E-mail)

S. Collins, RA M. Dapas, DRA R. Laufer, RI OEDO H. Chernoff, NRR P. Bamford, PM, NRR J. Hughey, NRR J. Lubinski, NRR M. Gamberoni, DRS J. Rogge, DRS K. Young, DRS P. Krohn, DRP R. Fuhrmeister, DRP S. Hansell, DRP - Senior Resident Inspector C. Bickett, DRP - Resident Inspector L. Pinkham - Resident OA Region I Docket Room (with concurrences)

ROPreports@nrc.gov DRS file Enclosure

U.S. NUCLEAR REGULATORY COMMISSION REGION I Docket No. 50-352, 50-353 License No. NPF-39, NPF-85 Report No. 05000352/2007006 and 05000353/2007006 Licensee: Exelon Generation Company, LLC Facility: Limerick Generating Station, Units 1 & 2 Location: Sanatoga, PA 19464 Dates: July 16, 2007 through August 3, 2007 Inspectors: K. Young, Senior Reactor Inspector, DRS P. Finney, Reactor Inspector, DRS J. Lilliendahl, Reactor Inspector, DRS O. Yee, Nuclear Safety Professional Development Program, DRS Approved by: John F. Rogge, Chief Engineering Branch 3 Division of Reactor Safety Enclosure

SUMMARY

OF FINDINGS IR 0500035212007006,05000353/2007006; 07/16/2007 - 08/03/2007; Exelon Nuclear; Limerick Generating Station, Units 1 and 2; Triennial Fire Protection Team Inspection.

The report covered a two-week triennial fire protection team inspection by three Region I specialist inspect<!rs. One Green finding was identified. The significance of most findings is indicated by their color (Green, White, Yellow) using Inspection Manual Chapter (IMe) 0609, "Significance Determination Process" (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation tif commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.

A. NRC-Identified Findings Cornerstone: Mitigating Systems

• Green. The team identified a finding of very low safety significance (Green) involving a non-cited violation of the Limerick Generating Station operating license, in that the procedure for shutting down the plant in response to a fire in the cable spreading room was not consistent with the safe shutdown analysis. Specifically, impediments related to the safe shutdown procedure would have prevented the operators from securing the high pressure coolant injection (HPCI) system within the design time limit. Fire induced cable failures in the cable spreading room could allow HPCI to overfill the reactor vessel which would adversely affect the operation of the reactor core isolation cooling (RCIC) system and the main steam relief valves (MSRVs).

This issue was more than minor because it affected the procedure quality attribute associated with the mitigating systems cornerstone as related to the objective of ensuring the reliability and availability of the RCIC system and MSRVs under postulated fire scenarios. The finding was of very low safety significance based on a Phase 2 Significance Determination Process (SDP) evaluation performed in accordance with IMC 0609, Appendix F, "Fire Protection Significance Determination Process." (Section 1R05.01)

B. Licensee-Identified Violations None ii Enclosure

REPORT DETAILS

Background

This report presents the results of a triennial fire protection inspection conducted in accordance with NRC Inspection Procedure (IP) 71111.05T, "Fire Protection." The objective of the inspection was to assess whether Exelon Nuclear, has implemented an adequate fire protection program and that post-fire safe shutdown capabilities have been established and are being properly maintained at the Limerick Generating Station (LGS). The following fire areas (FAs) were selected for detailed review based on risk insights from the LGS Individual Plant Examination of External Events (lPEEE):

• Fire Area 12

• Fire Area 23

• Fire Area 68

• Fire Area 79 The inspection team evaluated the licensee's fire protection program (FPP) against applicable requirements which included plant technical specifications, operating license condition 2.C.3, NRC safety evaluation reports (SERs), 10 CFR 50.48, and Branch Technical Position (BTP)

Chemical Engineering Branch (CMEB) 9.5-1. The team also reviewed related documents that included the Updated Final Safety Analysis Report (UFSAR), the fire hazards analysis (FHA),

and the safe shutdown analysis.

Specific documents reviewed by the team are listed in the attachment.

1. REACTOR SAFETY Cornerstones: Initiating Events, Mitigating Systems 1R05 Fire Protection

.01 Post-Fire Safe Shutdown From Outside the Main Control Room (Alternative Shutdown) and Normal Shutdown

a. Inspection Scope Methodology The team reviewed the safe shutdown analysis, operating procedures, piping and instrumentation drawings (P&IDs), electrical drawings, the UFSAR and other supporting documents to verify that hot and cold shutdown could be achieved and maintained from outside the control room for fires that rely on shutdown from outside the control room.

This review included verification that shutdown from outside the control room could be performed both with and without the availability of offsite power. Plant walkdowns were also performed to verify that the plant configuration was consistent with that described in the safe shutdown and fire hazards analyses. These inspection activities focused on ensuring the adequacy of systems selected for reactivity control, reactor coolant Enclosure

2 makeup, reactor decay heat removal, process monitoring instrumentation and support systems functions. The team verified that the systems and components credited for use during post-fire safe shutdown would remain free from fire damage. The team verified that the transfer of control from the control room to the alternative shutdown location(s) would not be affected by fire-induced circuit fatilts (e.g., by the provision of separate fuses and power supplies for alternative shutdown control circuits).

Similarly, for fire areas that utilize shutdown from the control room, the team also verified that the shutdown methodology properly identified the components and systems necessary to achieve and maintain safe shutdown conditions.

Operational Implementation The team verified that the training program for licensed and non-licensed operators included alternative shutdown capability. The team also verified that personnel required for safe shutdown using the normal or alternative shutdown systems and procedures were trained, available onsite at all times, and exclusive of those assigned as fire brigade members.

The team reviewed the adequacy of procedures utilized for post-fire safe shutdown and performed an independent walk through of procedure steps to ensure the implementation and human factors adequacy of the procedures. The team also verified that operators could reasonably be expected to I)erform specific actions within the time required to maintain plant parameters within specified limits. Time criiical actions which were verified included restoring alternating current (AC) electrical power, establishing remote shutdown panel operation, establishing reactor coolant makeup, and establishing decay heat removal.

Specific procedures reviewed for alternative shutdown, including shutdown from outside the control room included the following:

• SE-1, Remote Shutdown, Revision 24;

• 2FSSG-3023, Fire Area 23 Fire Guide, Revision 2; and

• 2FSSG-3068W, Fire Area 68W Fire Guide, Revision 2.

The team reviewed manual actions to ensure that they had been properly reviewed and approved and that the actions could be implemented in accordance with plant procedures in the time necessary to support the safe shutdown method for each fire area. The team also reviewed periodic testing records of the alternative shutdown transfer capability and instrumentation and control functions to ensure the tests demonstrated the functionality of the alternative shutdown capability.

b. Findings

Introduction:

The team identified a finding of very low safety significance (Green) involving a violation of the LGS operating license, in that the procedure for shutting Enclosure

3 down the plant in response to a fire in the cable spreading room was not consistent with the safe shutdown analysis. Specifically, human performance impediments related to the safe shutdown procedure would have prevented the operators from securing high pressure coolant injection (HPCI) within the design time limit. Fire induced cable failures in the cable spreading room could cause the spurious operation of the HPCI system .and result in overfill of the reactor vessel. This would affect the operation of reactor core isolation cooling (RCIC) system and the main steam relief valves (MSRVs).

Description:

LGS's thermal hydraulic analysis for fire safe shutdown, G-080-VC-00028, an.alyzes a scenario where a fire in the cable spreading room causes a spurious start of HPCI that also bypasses the HPCI level 8 automatic trip. For this scenario, there is a protected switch at the remote shutdown panel which will secure HPCI. The analysis determined that for the worst case conditions, HPCI must be secured within four minutes. If not secured promptly, HPCI would overfill the reactor vessel and water would enter the main steam lines which would adversely impact RCIC and the MSRVs.

Operator action to secure the HPCI system is credited in the fire safe shutdown analysis for the Unit 2 cable spreading room, LF-0016-023.

During the inspection, several walkdowns conducted in the plant and in the simulator were performed to assess the ability to secure HPCI within the specified four minutes.

During these walkdowns several complications were identified, two of which were significant. First, the single key required to secure the HPCI system was located inside a box containing sixty similar keys, but was not labeled for quick identification. Second, the procedure directing the operator to secure HPCI, procedure 2FSSG-3023, "Fire Area 023 Fire Guide," referred to a section in procedure SE-1, "Remote Shutdown,"

which was ambiguous since the exact step was not referenced and the necessary prerequisites were not identified. Based upon these human performance impediments and a demonstration conducted by the licensee which took nearly seven minutes to complete, the team had no confidence that the HPCI system could be secured within the four minute time limit.

Corrective action program issue report (IR) 656185 was written to address this issue.

LGS promptly added clear labeling for the HPCI key, revised all affected fire response procedures, and conducted operator training on securing HPCI following a postulated fire in the cable spreading room. The team concluded that these corrective actions were appropriate and provided reasonable assurance that a reactor vessel overfill event could be averted in the event of a spurious fire induced HPCI system initiation. A preliminary evaluation by LGS concluded that the thermal hydraulic analysis, of record, was overly conservative and that the time available to secure HPCI prior to vessel overfill may be between 6.5 to 7 minutes. The team learned that LGS was considering a revision to the design basis to extend the available time to the operators to secure HPCI.

The performance deficiency associated with this finding was that LGS failed to assure that an important time requirement in the safe shutdown analysis was translated and properly validated in the remote shutdown procedure. This deficiency resulted in operators not being able to secure HPCI within the fire safe shutdown credited four Enclosure

4 minute time limit. The licensee entered this performance deficiency into their corrective action program for resolution.

Analysis: The team referred to MC 0612 and determined this issue was more than minor because it affected the procedure quality attribute associated with the mitigating

• systems cornerstone as related to the objective of ensuring the reliability and availability of the RCIC system and MSRVs under postulated fire safe shutdown conditions.

The team assessed this finding in accordance with NRC Manual Chapter 0609, Appendix F, "Fire Protection Significance Determination Process." This finding affected operator response to postulated fires in the Unit 1 cable spreading room, the Unit 2 cable spreading room, and the combined control room. Based upon the screening criteria of Appendix F and using conservative fire scenario characterizations (medium degradation) and propagation (frequency and confinement), this finding screened to very low risk significance (Green) per Task No. 2.3.5. In support of this risk significance conciusion, the team noted that the Unit 1 and 2 cable spreading rooms are designated transient combustible free zones, fire/smoke detection systems alarm in the control room, automatic sprinkler systems and manual CO 2 suppression systems are installed, and the electrical cables installed are flame retardant in accordance with Institute of Electrical and Electronic Engineers (IEEE) 383, "IEEE Standard for Qualifying Class 1E Electric Cables and Field Splices for Nuclear Power Generating Stations." Similar fire scenario assumptions and design attributes were credited with respect to postulated fires in the control room and the team noted that the control room is continuously \

manned. Accordingly, the risk contribution to this finding associated with postulated control room fires is negligible. This significance determination was independently reviewed and verified by a Region I Senior Reactor Analyst.

Enforcement: License Condition 2.C.3 for LGS Unit 1 and Unit 2 states that, "Exelon Nuclear shall implement and maintain in effect all proVisions of the approved Fire Protection Program as described in the UFSAR." Appendix 9A of the UFSAR requires the licensee to comply with BTP CMEB 9.5-1, position C.5.c, Alternative or Dedicated Shutdown Capability. The BTP CMEB 9.5-1, position C.5.c.3 requires procedures to implement the capability to perform alternative (remote) shutdown. Contrary to these reqUirements, from approximately October 14, 2004, to August 3, 2007, the licensee's procedure for remote shutdown was not adequate to prevent overfilling of the reactor vessel following a spurious, fire-induced start of HPCI. Because the finding was ofvery low safety significance and has been entered into LGS's corrective action program (IR 656185), this violation is being treated as a non-cited violation (NCV), consistent with Section VI.A.1 of the NRC Enforcement Policy. NCV 05000352, 353/2007006-01, Inadequate Fire Safe Shutdown Procedure for Securing HPCI.

.02 Protection of Safe Shutdown Capabilities

a. Inspection Scope The team reviewed the fire hazards analysis, safe shutdown analyses and supporting Enclosure

5 drawings and documentation to verify that safe shutdown capabilities were properly protected. The team ensured that separation requirements of the UFSAR, were maintained for the credited safe shutdown equipment including supporting power, control and instrumentation cables. This review included an assessment of the adequacy of the selected systems for reactivity control, reactor coolant makeup, reactor heat removal, process monitoring, and associated support system functions.

The team reviewed the licensee's procedures and programs for the control of ignition sources and transient combustibles to assess their effectiveness in preventing fires and controlling combustible loading within limits established in the FHA. A sample of hot work and transient combustible control permits were also reviewed. The team performed plant walkdowns to verify that protective features were being properly maintained and administrative controls were being implemented.

The team also reviewed the licensee's design control procedures to ensure that the process included appropriate reviews and controls to assess plant changes for any potential adverse impact on the fire protection program and/or post-fire safe shutdown analysis and procedures.

b. Findings No findings of Significance were identified .

.03 Passive Fire Protection

a. Inspection Scope The team walked down accessible portions of the selected fire areas to observe the material condition and design adequacy of fire area boundaries (including walls, fire doors and dampers), and electrical raceway fire barriers to ensure they were appropriate for the fire hazards within the area.

The team reviewed installation/repair and qualification records for a sample of penetration seals to ensure the fill material was of the appropriate fire rating and that the installation met the engineering design. The team also reviewed similar records for fire protection wraps to ensure the material was of an appropriate fire rating and that the installation met the engineering design.

b. Findings No findings of Significance were identified.

Enclosure

6

.04 Active Fire Protection

a. Inspection Scope The team reviewed the design, maintenance, testing, and operation of the fire detection and suppression systems in the selected plant fire areas. This included verification that the manual and automatic detection and suppression systems were installed, tested, and maintained in accordance with the National Fire Protection Association (NFPA) code of record, or as NRC approved deviations, and that each suppression system would control or extinguish fires associated for the hazards in the selected areas. A review of the design capability of suppression agent delivery systems was verified to meet the code requirements for the fire hazards involved. The team also performed a walkdown of accessible portions of the detection and suppression systems in the selected areas as well as a walkdown of major support equipment in other areas (e.g.,

fire pumps, carbon dioxide (C0 2 ) storage tanks and supply system) and assessed the material condition of the systems and components.

The team reviewed electric and diesel fire pump flow and pressure tests to ensure that the pumps were meeting their design requirements. The team also reviewed the fire main loop flow tests to ensure that the flow distribution circuits were able to meet the design requirements.

The team assessed the fire brigade capabilities by reviewing training, qualification, and drill critique records. The team reviewed pre-fire plans and smoke removal plans for the selected fire areas to determine if appropriate information was provided to fire brigade members and plant operators to identify safe shutdown equipment and instrumentation, and to facilitate suppression of a fire that could impact post-fire safe shutdown. In addition, the team inspected the fire brigade's protective ensembles, self-contained breathing apparatus (SCBA), and various fire brigade equipment (including smoke removal equipment) to verify fire fighting readiness.

b. Findings No findings of significance were identified .

.05 Protection From Damage From Fire Suppression Activities

a. Inspection Scope The team reviewed documents and walked down the selected fire areas to verify that redundant trains of systems required for hot shutdown were not subject to damage from fire suppression activities or from the rupture or inadvertent operation of fire suppression systems. Specifically, the team verified that:

Enclosure

7

• A fire in one of the selected fire areas would not directly, through production of smoke, heat or hot gases, cause activation of suppression systems that could potentially damage all redundant safe shutdown trains.

• A fire in one of the selected fire areas (or the inadvertent actuation or rupture of a fire suppression system) would not directly cause damage to all redundant safe shutdown trains (e.g., sprinkler caused flooding of other than the locally affected train).

• Adequate drainage was provided in areas protected by water suppression systems.

b. Findings No findings of significance were identified .

.06 Alternative Shutdown Capabilitv Alternative shutdown capability for the selected fire areas inspection utilizes shutdown from outside the control room and is discussed in Section 1R05.01 of this report .

.07 Circuit Analyses

a. Inspection Scope The team verified that the licensee performed a post-fire safe shutdown analysis for the selected fire areas and that the analYSis appropriately identified the structures, systems, and components important to achieving and maintaining post-fire safe shutdown.

Additionally, the team verified that licensee's analysis ensured that necessary electrical circuits were properly protected and that circuits that could adversely impact safe shutdown due to hot shorts, shorts to ground, or other failures were identified, evaluated, and dispositioned to ensure spurious actuations would not prevent safe shutdown.

The team's review considered fire and cable attributes, potential undesirable consequences and common power supply/bus concerns. Specific items included the credibility of the fire threat, cable insulation attributes, cable failure modes, spurious actuations, and actuations that could result in a loss of coolant event.

The team also reviewed cable routing data sheets and wiring diagrams for a sample of components to verify that all necessary cables had been included in the safe shutdown analysis and that the routing ensures safe shutdown equipment cables remained free from fire damage. .

Enclosure

8 Cable failure modes were reviewed for the following components:

• HV49-2F029, HV49-2F031, RCIC Suppression Suction Valves;

• HV49-2F012, HV49-2F013, RCIC Pump Discharge Valves;

• I"SV41-2F013A, C, and N, SRVs;

• HV51-2F004A, HV51-2F006A, RHR Loop A Pump Suction Valves;

• 2AP202, RHR Pump A; and

• HV51-2F017A, LPCI Outboard Containment Isolation Valve.

The team reviewed circuit breaker coordination studies to ensure equipment needed to conduct post-fire safe shutdown activities would not be impacted due to a lack of coordination. The team confirmed that the coordination studies addressed multiple faults due to fire. Additionally, the team reviewed a sample of circuit breaker maintenance records to verify that circuit breakers for components required for post-fire safe shutdown were properly maintained in accordance with procedural requirements.

b. Findings No findings of significance were identified .

.08 Communications

a. Inspectio~ Scope The team reviewed safe shutdown procedures, the safe shutdown analysis, and associated documents to verify an adequate method of communications would be available to plant operators following a fire. During this review, the team considered the effects of ambient noise levels, clarity of reception, reliability, and coverage patterns.

The team also inspected the designated emergency storage lockers to verify the availability of portable radios for the fire brigade and plant operators. The team also verified that communications equipment such as repeaters and transmitters would not be affected by a fire.

b. Findings No findings of significance were identified .

.09 Emergency Lighting

a. Inspection Scope The team observed the placement and coverage area of eight-hour emergency lights throughout the selected fire areas and evaluated their adequacy for illuminating access and egress pathways and any equipment requiring local operation and/or instrumentation monitoring for post-fire safe shutdown. The team also verified that the battery power supplies were rated for at least an eight-hour capacity. Preventive Enclosure

9 maintenance procedures, the vendor manual, completed surveillance tests, and battery replacement practices were reviewed to verify that the emergency lighting was being maintained in a manner that would ensure reliable operation.

b. Findings No findings of significance were identified .

.10 Cold Shutdown Repairs

a. Inspection Scope The team verified that the licensee had dedicated repair procedures, equipment, and materials to accomplish repairs of components required for cold shutdown which might be damaged by the fire to ensure cold shutdown could be achieved within the time frames specific in their design and licensing bases. The inspectors verified that the repair equipment, components, tools, and materials (e.g. pre-cut cables with prepared attachment lugs) were available and accessible on site.

b. Findings No findings of Significance were identified .

. 11 Compensatory Measures

a. Inspection Scope The team verified that compensatory measures were in place for out-of-service, degraded, or inoperable fire protection and post-fire safe shutdown equipment, systems, or features (e.g., detection and suppression systems and equipment, passive fire barriers, pumps, valves or electrical devices providing safe shutdown functions or capabilities). The team also verified that the short term compensatory measures compensated for the degraded function or feature until appropriate corrective action could be taken and that licensee was effective in returning the equipment to service in a reasonable period of time.

b. Findings No findings of significance were identified.

Enclosure

10

4. OTHER ACTIVITIES 40A2 Identification and Resolution of Problems

.01 Corrective Actions for Fire Protection Deficiel'lcies

a. Inspection Scope The team verified that the licensee was identifying fire protection and post-fire safe shutdown issues at an appropriate threshold and entering them into the corrective action program. The team also reviewed a sample of selected issues to verify that the licensee had completed or planned appropriate corrective actions.

b. Findings No findings of significance were identified.

40A6 Meetings, Including Exit Exit Meeting SummarY On August 9, 2007, the team presented the inspection results to Mr. C. Mudrick, Site Vice President, and other members of the site ~taff, No proprietary information was included in this inspection report.

ATTACHMENT: SUPPLEMENTAL INFORMATION Enclosure

A-1 ATTACHMENT SUPPLEMENTAL INFORMATION KEY POINTS OF CONTACT Exelon Generation Company C. Mudrick, Site Vice President E. Callan, Plant Manager B. Dickinson, Director of Engineering P. Gardner, Director of Operations C. Rich, Director of Training S. Bobyock, Manger Engineering Programs J. Brittain, NOS C. Bruce, Fire Program Engineer F. Burzinski, Fire Marshall P. Chaso Supervisor S. Cleaver, Engineering Design Fire D. Doran, Sr. Manger Systems Engineering M. Evans, Systems Engineer Fire Protection D. Hamilton, Sr. Manager Engineering Design R. Harding, Regulatory Assurance R. George, Manager Electrical Design M. Jesse, Manager NOS E. Kelly, Engineering Manager R. Kreider, Manger Regulatory Assurance M. Kurchet, Dresden C. Pragman, Corporate Fire Protection M. Taylor, Corporate Fire Protection J. Rogge, Chief, Engineering Branch 3, Division of Reactor Safety W. Cook, Senior Reactor Analyst, Division of Reactor Safety S. Hansell, Senior Resident Inspector, LGS C. Bickett, Resident Inspector, LGS LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened NONE Attachment

A-2 Open and Closed 05000352, 353/2007006-01 NCV Inadequate Fire Safe Shutdown Procedure for Securing HPCI (Section 1R05.01)

Closed NONE Discussed NONE LIST OF DOCUMENTS REVIEWED Fire Protection Licensing Documents LGS, SER (NUREG 0991, 8/1983)

LGS, SSER2 LGS, SSER4 LGS UFSAR, Section 9.5, Other Auxiliary Systems, Fire Protection Program LGS UFSAR, Section 9A, Fire Protection Evaluation Report I Design Basis Documents L-S-39, RCIC Design Basis Document, Rev. 11 L-S"51, Fire Protection System, Rev. 5 L-T-10, LGS, Fire Safe Shutdown, Rev. 10 Calculations/Engineering Evaluation Reports/Specifications EAS-26-0489, LGS, Safe Shutdown Analysis for Fire Events, 5/1989 G-080-VC-00028, Thermal Hydraulic Analysis for Fire Events, Rev. 0 GE-NE-A13-00410-10, LGS, Assessment of Post Fire Safe Shutdown Methodology Changes, 12/1997 LEAF-0086, Walkdown Paths for FSSD Man. Actions/Repairs, Rev. 0 LEAM-0001, HPCI and RCIC Lds. During Fire Safe Shutdown, Rev. OA LF-0016-012, Fire Area 12 Fire Safe Shutdown Analysis, Rev. 0 LF-0016-023, Fire Area 23 Fire Safe Shutdown Analysis, Rev. 1 LF-0016-068E, Fire Area 68E Fire Safe Shutdown Analysis, Rev. 0 LF-0016-068W, Fire Area 68W Fire Safe Shutdown Analysis, Rev. 1 LF-0016-079, Fire Area 79 Fire Safe Shutdown Analysis, Rev. 1 NE-0294, Specification for Post-Fire Safe Shutdown Program Requirements at LGS, Rev. 3 Attachment

A-3 NPB-14, Moderate Energy Line Break Analysis for Reactor Enclosures, Rev. 6 NPB-57, MFPB Analysis - Fire Protection System Operation, Rev. 1 6900E.11, Load Circuit-Overcurrent Trip Devices, Rev. S 6900E.23, Safeguard 20S/120V AC Panel Circuit Breaker Coordination, Rev.1 S031-M-49-117-( 1)-2, Man. Water Spray Hydraulic Calc. Sys. WP-75, Rev.O S031-M-49-117 -(2)-1, Man. Water Spray Hydraulic Calc. Sys. WP-75, Rev.O 534749-45-02, Eval. of Ultra-Low Sulfur Diesel (ULSD) Fuel for Diesel Driven Fire Pumps Procedures A-C-134, Control of Hazard Barriers, Rev.4 A-C-134-5, Control of Hazard Doors/Hatches/Panels at Limerick Generating Station (LGS), Rev.15 CC-AA-209, Fire Protection Program Configuration Change, Rev.1 CC-MA-209-1001, Fire Protection Program Configuration Change Review, Rev.1 ER-AA-610-1001, Performance Based Evaluations for Fire Protection, Rev.3 ER-AA-610-1002, Fire Protection Program Performance Indicators, Rev.1 OP-AA-201-001, Fire Marshal Tours, Rev.2 OP-AA-201-002, Fire Reports, Rev.2 OP-AA-201-003, Fire Drill Performance, Rev.S OP-MA-201-004, Fire Protection for Hot Work, Rev.1 OP-AA-201-005, Fire Brigade Qualification, Rev. 5 OP-AA-201-006, Control of Temporary Heat Sources, Rev.3 OP-MA-201-007, Fire Protection System Impairment Control, Rev.4 OP-AA-201-00S, Pre-Fire Plans, Rev.1 OP-AA-201-009, Control of Transient Combustible Material, Rev.5 ST-6-022-551-0, Fire Drill, Rev.7 Operations Procedures 1FSSG-3012, Fire Area 12 Fire Guide, Rev. 3 1FSSG-306SW, Fire Area 6SW Fire Guide, Rev. 2 2FSSG-3023, Fire Area 23 Fire Guide, Rev. 2 2FSSG-3023, Fire Area 23 Fire Guide, Rev. 3 2FSSG-3079, Fire Area 79 Fire Guide, Rev. 0 OP-LG-101-111, Shift Staffing Requirements, Rev. 0 S92.1.0, Local and Remote Manual Startup of a Diesel Generator, Rev. 46 SA-AA-129, Electrical Safety, Rev. 4 SE-1, Remote Shutdown, Rev. 54 SE-1, Remote Shutdown, Rev. 55 SE-1-1, Protected Depressurization Control, Rev. 12 SE-1-2, Protected Power Source, Rev. 7 Attachment

A-4

. SE-1-3, Protected Ventilation Source, Rev. 10 SE-8, Fire, Rev. 30 Completed Tests/Surveillances RT-2-085-600-0, Functional Test of Alternate Shutdown Communication System, Rev. 11, Completed 4/24/2007 RT-2-108-300-1, FSSD ELU 8 Hour Capacity Verification Test, Rev.9, Completed 09/26/06 RT-2-108-300-2, FSSD ELU 8 Hour Capacity Verification Test, Rev.9, Completed 10/18/06 RT-6-000-900-0, Inspection of Safe Shutdown Equipment, Completed 1/31/06, 8/7/06, & 2/1/07 RT 000-994-0, Verification of Operator Qualifications, Rev.11, Completed 05/30/07 ST-2-022-601-1, Fire Detection - Fire Detection Instrumentation Channel Functional Test and Supervisory Circuit Operability Test, Zones 7,8,9,12,13,14 and 15, Rev.21, Completed 05/19/06, Rev.20, Completed 11/03/06 ST-2-022-602-2, Fire Detection - Smoke Detection Instrumentation Channel Functional Test and Supervisory Circuit Operability Test, Zones 21,23, Rev.11, Completed 02/08/05, Rev.13, Completed 02/07/06 ST-2-022-61 0-2, Fire Detection - Smoke Detection Instrurnentation Channel Functional Test and Supervisory Circuit Operability Test, Zones 68A, 688, 68C, Rev.14, Completed 05/12106, Rev.15, Completed 02/21/07 ST-2-022-620-1, Fire Detection - Fire Detection Instrumentation Channel Functional Test and Supervisory Circuit Operability Test, Zone 79, Rev.18, Completed 11/14/06 & OS/29/07 ST 022-642-2, Fire Detection - Heat Detection Instrumentation Channel Functional Test and Supervisory Circuit Operability Test, Zone 68A, Rev.9, Completed 12/15/06 & 07/21/06 ST-2-088-320-1, Remote Shutdown System RCIC Operability Test, Completed 6/2/2005 ST-2-088-320-2, Remote Shutdown System RCIC Operability Test, Completed 8/12/2005 ST-4-022-920-1, Fire Rated Assembly Inspection, Rev.3, Completed OS/26/06, Rev.4, Completed OS/24/07 ST-4-022-950-0, Spray and Sprinkler Visual Inspection, Rev.3, Completed 02/12/07 ST-6-022-250-0, Underground Fire Main Flow Test, Rev.4, Completed 09/29/05 &

09/29/06 ST-6-022-252-0, Diesel Driven Fire Pump Flow Test, Rev.27, Completed 06/04107, Rev.26, Completed 05/11/07

. ST-6-022 -253-0, Diesel Driven Fire Pump Characteristic Curve Test, Rev.5, Completed 05/11/07, Rev.6, Completed 05/18/07 Attachment

A-5 ST-6-022-254-0, Motor Driven Fire Pump Characteristic Curve Test, Rev.3, Completed 12/26/05, Rev.5, Completed 06/26/07 ST-6-022 -320-0, Unit 1 and Common FSWS Operability Verification, Rev.O, Completed 12/16/06 ST 022-600-0, FSWS Flush, Rev.13, Completed 09/22/06 Quality Assurance (QA) Audits and Self Assessments LS-AA-126-1001, LGS, Focused Self-Assessment, Fire Protection Program, Rev. 4 System Health Reports LIM 091, U1 - 13KV System, 5/2007 LIM 091, U2 - 13KV System, 5/2007 LIM P092B, U1 - 4 KV System, 5/2007 LIM P092B, U2 - 4 KV System, 5/2007 LIM 093, UO - 480 V System, 5/2007 LIM 093, U1 - 480 V System, 5/2007 LIM 093, U2 - 480 V System, 5/2007 LIM 094, U1 - 120 VAC System, 5/2007 LIM 094, U2 - 120 VAC System, 5/2007 LIM 095, U1 - DC System, 5/2007 LIM 095, U2 - DC System, 5/2007 Engineering Change Reguests LG 96-02491, UFSAR Change to Provide Explanatory Notes for Fire Drills, Rev.O LG-97-03146, Installation Package, ESW Pump A, 11/12/97 LG-97-03148, Mod P000701-1:lnstallation Package, EDG 1AG501, 11/12/97 LG 01-00897, Barriers and Defensive Positions - Control Structure, Rev.O Drawings & Wiring Diagrams C-11, Sht. 1, Yard-work Fire System, Rev.44 C-191,Sht.1, Reactor Building Units 1 & 2 Structural Steel Column Schedule, Rev.24 C-191, Sht. 2, Reactor Building Units 1 & 2 Structural Steel Fire Proofing Column Schedule, Rev.O C-756, Control Room Area Interior Walls EI.180'-0" to EI.332'-0" Area 8, Rev.21 E-1,Sht.1, Single Line Diagram Station, Rev. 26 E-15, Single Line Meter & Relay Diagram 4 KV Safeguard Power System 1 Unit, Rev. 27 E-16, Single Line Meter & Relay Diagram 4 KV Safeguard Power System 2 Unit, Rev. 22 Attachment

A-6 E-24, Single Line Meter & Relay Diagram Load Center Load Tabulation Safeguard Load Center - 1 & 2 Units, Rev. 19 E-26, Shts. 1-2, Single Line Diagram, 120V AC Power Supply HVAC Safeguard MOVs & Dampers E-28,

• Single Line Meter & Relay Diagram 0114, 0124, 0134, 0144, Safeguard Load Centers, 440 V - 1 Unit, Rev. 18 E-29, Single Line Meter & Relay Diagram 0214, 0224, 0234, 0244, Safeguard Load Centers, 440 V - 2 Unit, Rev. 17 E-30, Shts. 1-3, Single Line Diagram Instrumentation AC System 1 Unit E-31, Shts. 1-3, Single Line Diagram Instrumentation AC System 2 Unit E-33, Shts. 1-3, Single Line Meter & Relay Diagram 125/250 VDC System 2 Unit E-34, Shts. 1-3, Single Line Meter & Relay Diagram 125/250 VDC System 2 Unit E-80, Schematic Meter & Relay Diagram 011 & 012 Safeguard Buses, 4KV 1 Unit, Rev. 18 E-81, Schematic Meter & Relay Diagram 013 & 014 Safeguard Buses, 4KV 1 Unit, Rev. 20 E-82, Schematic Meter & Relay Diagram 021 & 022 Safeguard Buses, 4KV 2 Unit, Rev. 19 E-83, Schematic Meter & Relay Diagram 023 & 024 Safeguard Buses, 4KV 2 Unit, Rev. 21 E-84, Schematic Meter & Relay Diagram Diesel Generators, 4KV 1&2, Rev. 18.

E-102, I Schematic Block Diagram RHR System 1 & 2 Units, Rev. 33 E-105, Schematic Diagram RCIC System 1 & 2 Units, Rev. 28 E-110, Schematic Block Diagram Auto Depressurization & Standby Liquid Control Systems - 1 & 2 Units E-321 , Sht. 2, Emergency Service Water Pumps - Common, Rev. 19 E-360, Schematic Diagram RHR Pumps 1 & 2 Units E-591 , Shts. 1-2, 011 Diesel Generator Control & Auxiliaries E-1652, Sht.1, Communication & Fire Alarm Layout Turbine Enclosure Unit 1 Above EI.239'-0" & 254'-0", Rev.18 E-1667, Sht.1, Communication & Fire Alarm Diesel Generator Enclosure Unit 1 Above EI.217'-0", Rev.7 E-1672, Sht.1, Communication & Fire Alarm Layout Turbine Enclosure Unit 2 Plan Above EI.239'-0" & 254'-0", Rev.3 E-1683, Sht.1, Communication & Fire Alarm Layout Reactor Enclosure - Unit 2 Plan Above EI.253'-0", Rev. 10 M-1-B21-1060-E-006, Elementary Dia. Auto Depressurization System, Rev. 19 M-1-B21-1060-E-020, Elementary Dia. Auto Depressurization System, Rev. 7 M-1-C61-1050-E-016.3, Elementary Dia. Remote Shutdown System, Rev. 1 M-1-C61-1050-E-021.1, SRV Scheme, Rev. 17 M-1-E11-1040-E-032, Elementary Diagram RHR System M-1-E11-1040-E-048, Elementary Diagram RHR System, Rev. 12 M-1-E41-1040-E-021, HPCI System Elementary Diagram, Rev. 12 M-1-E41-1040-E-025, HPCI System Elementary Diagram, Rev ..11 M-1-E51-1040-E-020, Elementary Diagram Reactor Core Isolation, Rev. 10 Attachment

A-7 M-1-E51-1040-E-033, Elementary Diagram Reactor Core Isolation, Rev. 1 M-22, Shts. 1 - 9, Fire Protection M-71-65, Shts. 1-2, D11 Diesel Generator M-1045, Heating, Venting & Air Conditioning Control Area Cable Spreading Room, Rev.32 PSA-761, Control Room Area Room B Interior Wall, Rev.13 PSA-762, Control Room Area BlnteriorWall Elevations Wall Nos.59 thru 67

& 107, Rev.11 PSA-1BO-2, Sht.1, Reactor Building Unit 2 Exterior Wall Penetrations Col. Line J Above EI.217'-0", Rev.9 PSA-1BO-2, Sht .5, Reactor Building Unit 2 Exterior Wall Penetrations Col. Line J Above EI.217'-0", Rev.3 2B6-1, Sht. 9, Pipe or Conduit thru 3 Hour Rated Fire Barrier, Rev.O B031-M-10049.20, Typical 3-Hour Fire Barrier Penetrations, Rev.1 B031-NE-75-1.5, Cables through Sleeves, Rev.1 B031-M-10049.15, Typical 3 Hr Fire Barrier Penetrations, Rev.1 13517, DAF-P-475BM Fire Door, Rev. A Piping & Instrumentation Diagrams B031-M-41, Shts. 1 - 6, Nuclear Boiler Unit B031-M-49, Shts. 1 - 2, Reactor Core Isolation Cooling B031-M-50, Shts. 1 - 4, RCIC Pump Turbine B031-M-51, Shts. 1 - B, Residual Heat Removal B031-M-52, Shts. 1 - 4, Core Spray B031-M-55, Shts. 1 - 2, High Pressure Coolant Injection B031-M-56, Shts. 1 - 4, HPCI PumplTurbine Vendor Manuals 9140052262, Lightguard F100 Vendor Manual, Rev.O 9140052272, Lightguard FB5 Vendor Manual, Rev.O Pre-Fire Plans F-A-434, Unit 1 D13 Emerg 4KV Switchgear Room 434 (EI. 239) Fire Area 12, Rev.B, Rev.9 F-A-450, Unit 2 Cable Spreading Room (EI.254') Fire Area 23, Rev.7, Rev.B F-D-311A, D11 Diesel Generator Room and Fuel Oil and Lube Oil Tank Room Rms 311A and 312A (E1.217) Fire Area 79, Rev.5, Rev.6 F-R-475, Unit 2 CRD Equipment and Neutron Monitoring Areas Rooms 475, 476, 477,479 (E1.253) Fire Area 6B, Rev.11 Attachment

A-8 Fire Drill Reports R1035 63509 /29/06 R1048 77412 /14/06 R1048000 12122106 R1049330 12/16/06 R0132 86507 /21/06 R1047776 09/28 /06.

R1047 49409 /28/06 R0979387 02/09/ 05 R0976593 09/23/ 04 R0971 077 09/23/04 R0960 70304 /18/04 R0952167 03/26/04 R1020651 06/01/ 06 R1013883 01/26/06 R1 03563 509/29 /06 R 1044553 09/28/06 R 1048774 12/14/06 R0966687 07108/04 R0964102 07/16/ 04 R0964993 07/22104 R0965 53207 /29/04 R0962767 08/05/04 Fire Brigade Training LGS Fire Brigade Training Records 01/25/06, 05/31/06.

Operator Safe Shutdown Training Lic. Oper. Requal, Long Range Training Plan, Rev. 10 LLOJPM0207, JPM: Emergency Power to OB ESW Pump, Rev. 9 7

LLOJPM0250, JPM: Emergency Powllr to RCIC Inboard Isolation Valve, Rev.

of LPCI, Rev. 2 LLOJPM0267, JPM: Alignment of Equip. for Manual Operation LLOJPM0268, JPM: Align. of Long Term Pneumatics for MSRV Op., Rev. 1 0

LLOR0403D, Licensed Oper. Requal, SE-1 and SE-6 In-Plant Training, Rev.

LLOR0702A, Licensed Operator Requal, Simulator Training Outline, Rev. 0 0

LLOR-07021, Lic. Oper. Requal, Fire Safe Shutdown Guides - SE-1-3, Rev.

in Cable Spread Room, Rev. 8 LSTS-3403, Simulator Training Scenario, Fire Shift Train. Doc., Prompt Action for HPCI Trip at RSP, 8/3/07 S01-0 7-046, Hot Work and Ignition Source Permits R1051640 M1605508 C0220386 Impairment Permits A1618979 A1437776 A1437799 A1511486 A1621745 A1507935 Attachment

A-9 Transient Combustible Evaluations A1559298-E53, -E54, -E55, -E57, -E58 Miscellaneous Documents Archival Operations Narrative Logs from 05/11/07 to 07/18/07 Bisco Reports, 748-63-A 03/11/82,748-6401/15/82,748-22004/15/87 INDMS - Cable Location Report INDMS - Safe & Alternative Shutdown Logics NRC Sup. Guid. "Nuclear Plant Fire Protection Functional Responsibilities,"

08/29/77 EPRI TR-106826, Battery Performance Monitoring by Internal Ohmic Measurements, 12/96 Pre-Operational Test Procedure 2P-13.2, Rev.O Startup Field Report 233D-007 Cable Spreading Room Unit 2 IISCP for PSL-022-026 Issue Rports A1354849-E5, E8, E10-12 A1605498 A1615942 273644 260417 267117 359446 469105 248630 446569 523298 581869 605434 607695 617637 619104 621537 621631 627970 628363 630245 635086 649568* 650778* 650889* 650922* 650953*

651373* 651670* 651688* 653136* 654520* 654564*

655258* 656185* 656195* 656207* 656255* 656506*

656756*

• NRC identified during this inspection Work Orders C0213924 R0631 000 R0631 028 R0659528 R0662281 R0709266 R0965868 Attachment

A-10 LIST OF ACRONYMS USED AC Alternating Current ADAMS Agency Documents Access and Management System BTP Branch Technical Position CFR Code of Federal Regulations CMEB Chemical Engineering Branch CO2 Carbon Dioxide DRS Division of Reactor Safety FA Fire Area FHA Fire Hazards Analysis FPP Fire Protection Program HPCI High Pressure Coolant Injection IEEE Institute of Electrical & Electronic Engineers IMC Inspection Manual Chapter IP Inspection Procedure IPEEE Individual Plant Examination of External Events IR Inspection Report IR Information Request LGS Limerick Generating Station LPCI Low Pressure Coolant Injection MSRV Main Steam Relief Valve NCV Non-cited Violation NFPA National Fire Protection Association NRC Nuclear Regulatory Commission PARS Publicly Available Records P&ID Piping and Instrumentation Drawing RCIC Reactor Core Isolation Cooling RHR Residual Heat Removal SCBA Self Contained Breathing Apparatus SOP Significance Determination Process SER Safety Evaluation Report SUNSI Sensitive Unclassified Non-Safeguards Information UFSAR Updated Final Safety Analysis Report Attachment

UNITED STATES NUCLEAR REGULATORY COMMISSION REGION I 475 ALLENDALE ROAD KING OF PRUSSIA, PA 19406-1415 June 14, 2010 Mr. Michael Pacilio Senior Vice President, Exelon Generating Company, LLC President and Chief Nuclear Officer, Exelon Nuclear 4300 Winfield Rd.

Warrenville, IL 60555

SUBJECT:

LIMERICK GENERATING STATION - NRC TRIENNIAL FIRE PROTECTION INSPECTION REPORT 0500035212010006 AND 05000353/2010006

Dear Mr. Pacilio:

On May 28,2010, the U.S. Nuclear Regulatory Commission (NRC) completed a triennial fire protection inspection at Limerick Generating Station. The inspectors also reviewed mitigation strategies for addressing large fires and explosions. The enclosed inspection report documents the inspection results, which were discussed on May 28, 2010, with Mr. William Maguire and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations, and with the conditions of your license. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

Based on the results of this inspection, no findings of significance were identified.

In accordance with Title 10 of the Code of Federal Regulations Part 2.390 of the NRC's "Rules of Practice: a copy of this letter, its enclosure, and your response (if any) will. be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRC's document system (ADAMS).

ADAMS is accessible from the NRC Web Site at http:/twww.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

~::~

Engineering Branch 3 Division of Reactor Safety Docket Nos. 50-352, 50-353 License Nos. NPF-39, NPF-85

Enclosure:

Inspection Report No. 05000352/2010006 and 05000353/2010006 w/

Attachment:

Supplemental Information cc: Distribution via ListServ Enclosure 6

June 10, 2010 Mr. Michael Pacilio Senior Vice President, Exelon Generating Company, LLC President and Chief Nuclear Officer, Exelon Nuclear 4300 Winfield Rd.

Warrenville, IL 60555

SUBJECT:

LIMERICK GENERATING STATION - NRC TRIENNIAL FIRE PROTECTION INSPECTION REPORT 05000352/2010009 AND 05000353/2010006

Dear Mr. Pacilio:

On May 28, 2010, the U.S. Nuclear Regulatory Commission (NRC) completed a triennial fire protection inspection at Limerick Generating Station. The inspectors also reviewed. mitigation strategies for addressing large fires and explosions. The enclosed inspection report documents the inspection results, which were discussed on May 28, 2010, with Mr. William Maguire and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations, and with the conditions of your license. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

Based on the results of this inspection, no findings of significance were identified.

In accordance with Title 10 of the Code of Federal Regulations Part 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRC's document system (ADAMS).

ADAMS is accessible from the NRC Web Site at htlp:llwww.nrc.gov/reading-rm/adams.html(the Public Electronic Reading Room).

Sincerely, IRA!

John F. Rogge, Chief Engineering Branch 3 Division of Reactor Safety Docket Nos. 50-352, 50-353 License Nos. NPF-39, NPF-85

Enclosure:

Inspection Report No. 0500035212010006 and 05000353/2010006 w/Atlachment: Supplemental Information cc: Distribution via ListServ ADAMS ACCESSION NO: ML101650139 SUNSI Review Complete: JFR (Reviewer's Initials)

DOCUMENT NAME: G:\DRS\Engineering Branch 3\Young\LlMERICK FP 2010-06.doc After declaring this document"An Official Agency Record" it will be released to the Public.

. I ~~~~~~~~

OFFICIAL RECORD COPY

M. Pacilio 2 Distribution w/encl:

S. Collins, RA (R10RAMAIL Resource)

M. Dapas, DRA (R10RAMAIL Resource)

D. Lew, DRP (R1DRPMAIL Resource)

1. Clifford, DRP (R1DRPMAIL Resource)

D. Roberts, DRS (R1DRSMail Resource)

P. Wilson, DRS (R1DRSMail Resource)

J. Rogge, DRS .

K. Young, DRS P. Krohn, DRP A. Rosebrook, DRP E. Torres, DRP J. Bream, DRP E. DiPaolo, DRP, SRI N. Sieller, DRP, RI L. Trocine, RI, OEDO D. Bearde, DRS RidsNrrPMLimerick Resource ROPreportsResource@nrc.gov_

\

u.s. NUCLEAR REGULATORY COMMISSION REGION I

. Docket Nos.: 50-352, 50-353 License Nos.: NPF-39, NPF-85 Report Nos.: 0500035212010006 and 05000353/2010006 Licensee: Exelon Generation Company, LLC Facility: Limerick Generating Station, Units 1 & 2 Location: Sanatoga, PA 19464 Dates: May 10 through May 28, 2010 Inspectors: K. Young, Senior Reactor Inspector, Division of Reactor Safety (DRS (Team Leader)

W. Cook, Senior Reactor Analyst, DRS R. Fuhrmeister, Senior Reactor Inspector, DRS J. Rady, Reactor Inspector, DRS N. Lafferty, Reactor Inspector (Observer), Division of Reactor Projects (DRP)

S. Philpott, Project Manager, Licensing Process Branch (Observer),

Office of Nuclear Reactor Regulation (NRR)

Approved by: John F. Rogge, Chief Engineering Branch 3 Division of Reactor Safety

SUMMARY

OF FINDINGS 2010; Exelon Generation IR 0500035212010006, 05000353/2010006; 05/10/2010 - 05/28/

Trienn ial Fire Protec tion Team Inspection.

Company, LLC; Limerick Generating Station:

tion by Region I specialist The report covered a two-week triennial fire protection team inspec ion of commercial nuclear power inspectors., The NRC's program for overseeing the safe operat s," Revision 4, dated reactors is described in NUREG-1649, "Reactor Oversight Proces December 2006.

Cornerstone: Mitigating Systems No findings of significance were identified.

Other Findings None 1

ii

REPORT DETAILS

Background

This report presents the results of a triennial fire protection inspection conducted in accordance with NRC Inspection Procedure (IP) 71111.05T, "Fire Protection." The objective of the inspection was to assess whether Exelon Generation Company, LLC has implemented an adequate fire protection program and that post-fire safe shutdown capabilities have been established and are being properly maintained at the Limerick Generating Station (LGS). The following fire areas (FAs) were selected for detailed review based on risk insights from the LGS Individual Plant Examination (IPE)lIndividual Plant Examination of External Events (lPEEE):

• FA 2;

• FA 7;

• FA 22; and

• FA 67.

Inspection of these areas/zones fulfills the inspection procedure requirement to inspect a minimum of three samples.

The inspection team evaluated the licensee's fire protection program (FPP) against applicable requirements which included plant Technical Specifications, Operating License Condition 2.C.(3), NRC Safety Evaluations Reports (SERs), 10CFR 50.48, and Branch Technical Position (BTP) Chemical Engineering Branch (CMEB) 9.5-1. The team also reviewed related documents that included the Updated Final Safety Analysis Report (UFSAR), Section 9.5, the fire hazards analysis (FHA), and the post-fire safe shutdown analysis.

The team also evaluated licensee mitigating strategies for addressing large fires and explosions as required by Operating License Conditions 2.C.(21) for Unit 1 and 2.C.(9) for Unit 2.

Specific documents reviewed by the team are listed in the attachment.

1. REACTOR SAFETY Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity 1R05 Fire Protection (lP 71111.05T)

.01 Post-Fire Safe Shutdown From Outside Main Control Room (Alternative Shutdown) and Normal Shutdown Enclosure

2

a. Inspection Scope Methodology The team reviewed the safe shutdown analysis, operating procedures, piping and instrumentation drawings (P&IDs), electrical drawings, the UFSAR and other supporting documents to verify that hot and cold shutdown could be achieved and maintained for fires that rely on shutdown from outside the control room. This review included verification that shutdown from outside the control room could be performed both with and without the availability of offsite power. Plant walkdowns were also performed to verify that the plant configuration was consistent with that described in the safe shutdown and fire hazards analyses. These inspection activities focused on ensuring the adequacy of systems selected for reactivity control, reactor coolant makeup, reactor decay heat removal, process monitoring instrumentation, and support systems functions. The team verified that the systems and components credited for use during this shutdown method would remain free from fire damage. The team verified that the transfer of control from the control room to the alternative shutdown location(s) would not be affected by fire-induced circuit faults (e.g. by the provision of separate fuses and power supplies for alternative shutdown control circuits).

Similarly, for fire areas that utilize shutdown from the control room, the team also verified that the shutdown methodology properly identified the components and systems necessary to achieve and maintain safe shutdown conditions.

\

Operational Implementation The team verified that the training program for licensed and non-licensed operators included altemative shutdown capability. The team also verified that personnel required for safe shutdown using the normal or alternative shutdown systems and procedures are trained and available onsite at all times, exclusive of those assigned as fire brigade members.

The team reviewed the adequacy of procedures utilized for post-fire safe shutdown and performed an independent walk through of proced'ure steps to ensure the implementation and human factors adequacy of the procedures. The team also verified, that the operators could be reasonably expected to perform specific actions within the time required to maintain plant parameters within specified limits, Time critical operator actions, which were verified, included restoration of alternating current (AC) electrical power, establishing the remote shutdown and local shutdown panels, establishing reactor coolant makeup, and establishing decay heat removal.

Specific procedures reviewed for alternative shutdown, including shutdown from outside the control room included the following:

• SE-1, Remote Shutdown, Revision 63;

• 1FSSG-3002, 13 kV Switchgear Area (U-1), Revision 6;

• 1FSSG-3002, 13 kV Switchgear Area (U-2), Revision 5;

• 2FSSG-2007, Corridor (4 kV), Revision 6;

• 2FSSG-3022, Fire Area 22 Fire Guide, Revision 7; Enclosure

3

• 2FSSG-3067E, Safeguard System Access Area East, Revision 4; and

• 2FSSG-3067W, Safeguard System Access Area East, Revision 4.

The team reviewed manual actions to ensure that they had been properly reviewed and approved and that the actions could be implemented in accordance with plant procedures in the time necessary to support the safe shutdown method for each fire area. The team also reviewed the periodic testing of the alternative shutdown transfer capability and instrumentation and control functions to ensure the tests are adequate to ensure the functionality of the alternative shutdown capability.

b. Findings No findings of significance were identified .

.02 Protection of Safe Shutdown Capabilities

a. Inspection Scope The team reviewed the FHA, safe shutdown analyses, and supporting drawings and documentation to verify that safe shutdown capabilities were properly protected. The team ensured that separation requirements of the UFSAR were maintained for the credited safe shutdown equipment and their supporting power, control, and instrumentation cables. This review included an assessment of. the adequacy of the selected systems for reactivity control, reactor coolant makeup, reactor heat removal, process monitoring, and associated support system functions.

The team reviewed the licensee's procedures and programs for the control of ignition sources and transient combustibles to assess their effectiveness in preventing fires and in controlling combustible loading within limits established in the FHA. A sample of hot work and transient combustible control permits were also reviewed. The team performed plant walkdowns to verify that protective features were being properly maintained and administrative controls were being implemented.

b. Findings No findings of significance were identified .

.03 Passive Fire Protection

a. Inspection Scope The team walked down accessible portions of the selected fire areas to observe material condition and the adequacy of design of fire area boundaries (including walls, fire doors, and fire dampers), and electrical raceway fire barriers to ensure they were appropriate for the fire hazards in the area.

The team reviewed installation/repair and qualification records for a sample of penetration seals to ensure the fill material was of the appropriate fire rating and that the installation met the engineering design. The team also reviewed sfmilar records for the Enclosure

4 fire protection wraps to ensure the materi al was of an appropriate fire rating and that the installation met the engineering design.

b. Findings No findings of significance were identified. *

.04 Active Fire Protection

a. Ins(?ection Sco(?e ion of the fire detection The team reviewed the design, maintenance, testing, and operat included verification that and suppression systems in the selected plant fire areas. This were installed, tested, the manua l and automatic detection and suppression systems Association (NFPA )

and maintained in accordance with the National Fire Protection ssion system would code of record, or NRC approved deviations, and that each suppre hazard s in the selecte d areas. A control and/or extinguish fires associated with. the deliver y system s were verified review of the design capability of the suppression agent team also perform ed a to meet the code requirements for the hazards involved. The system s in the walkdown of accessible portions of the detection and suppression equipment in other areas selected areas as well as a walkdown of major system support and supply system)

(e.g. fire pumps, Halon, and/or carbon dioxide (C02) storage tanks to asses s the material condition of the system s and components.

re tests to ensure that The team reviewed electric and diesel fire pump flow and pressu The team also reviewed the fire the pumps were meeting their design requirements.

were able to meet the main loop flow tests to ensure that the flow distribution circuits design requirements.

, qualification, and The team assessed the fire brigade capabilities by reviewing training smoke removal plans drill critique records. The team also reviewed pre-fire plans and was provided to fire for the selected fire areas to determine if appropriate information y safe shutdo wn equipm ent and brigade members and plant operators to identif that could impact post-fire safe instrumentation, and to facilitate suppression of a fire fire brigad e eqUipm ent shutdown capability. In addition, the team inspected the readin ess for fire (including smoke removal equipment) to determine operational fighting.

b. Findings No findings of significance were identified .

.05 Protection From Damage From Fire Su(?(?ression Activities

a. Inspection Scope verify that redundant The team performed document reviews and plant walkdowns to e from fire trains of systems required for hot shutdown are not subject to damag Enclosure

5 suppression activities or from the rupture or inadvertent operation of fire suppression systems. Specifically, the team verified that

• A fire in one of the selected fire areas would not directly, through production of smoke, heat, or hot gases, cause activation of suppression systems that could potentially damage all redundant safe shutdown trains;

• A fire in one of the selected fire areas (or the inadvertent actuation or rupture of a fire suppression system) would not directly cause damage to all redundant

. trains (e.g. sprinkler caused flooding of other than the locally affected train); and,

• Adequate drainage is provided in areas protected by water suppression systems.

b. Findings No findings of Significance were identified .

.06 Altemative Shutdown Capabilitv

a. Inspection Scope Altemative shutdown capability is discussed in section 1R05.01 of this report .

.07 Circuit Analysis

a. Inspection Scope The team verified that the licensee performed a post-fire safe shutdown analysis for the selected fire areas and the analysis appropriately identified the structures, systems, and components important to achieving and maintaining safe shutdown. Additionally, the team verified that the licensee's analysis ensured that necessary electrical Circuits were properly protected and that circuits that could adversely impact safe shutdown due to hot shorts, shorts to ground, or other failures were identified, evaluated, and dispositioned to ensure spurious actuations would not prevent safe shutdown.

The team's review considered fire and cable attributes, potential undesirable consequences and common power supply/bus concems. Specific items included the credibility of the fire threat, cable insulation attributes, cable failure modes, and actuations resulting in flow diversion or loss of coolant events.

The team also reviewed cable raceway drawings for a sample of components required for post-fire safe shutdown to verify that cables were routed as described in the cable routing matrices.

Cable failure modes were reviewed for the following components:

• HV-11-071, Loop 'A' Equipment Header Retum Valve;

• HV-49-2FOOB, Steam Supply Line Outboard Containment Isolation Valve;

• HV-51-1 F014A, RHR Heat Exchanger Tube Inlet Valve;

• HV-51-1 F047A, Heat Exchanger Inlet Valve (from Pump Discharge);

Enclosure

6

• HV-51-003A, Heat Exchanger Shell Side Discharge Valve;

• HV-51-2F021A, Drywall Spray Line Inboard Containment Isolation Valve;

• U-42-2R010, Reactor Vessel Water Level Indicator; and,

• OAP506, Loop 'A' RHRSW Pump .

• The team reviewed circuit breaker coordination studies to ensure equipment needed to conduct post-fire safe shutdown activities would not be impacted due to a lack of coordination. The team confirmed that coordination studies had addressed multiple faults due to fire. Additionally, the team reviewed a sample of circuit breaker maintenance records to verify that circuit breakers for components required for post-fire safe shutdown were properly maintained in accordance with procedural requirements.

b. Findings No findings of significance were identified.

.08 Communications

a. Inspection Scope The team reviewed safe shutdown procedures, the safe shutdown analysis, and associated documents to verify an adequate method of communications would be available to plant operators following a fire. During this review the team considered the 1 effects of ambient noise levels, clarity of recepiion, reliability, and coverage patterns.

The team also inspected the deSignated emergency storage lockers to verify the availability of portable radios for the fire brigade and for plantoperators. The team also verified that communications equipment such as repeaters and transmitters would not be affected by a fire.

b. Findings No findings of significance were identified .

.09 Emergency Lighting

a. . Inspection Scope The team observed the placement and coverage area of eight-hour emergency lights throughout the selected fire areas to evaluate their adequacy for illuminating access and egress pathways and any equipment requiring local operation and/or instrumentation monitoring for post-fire safe shutdown. The team also verified that the battery power supplies were rated for at least an eight-hour capacity. Preventive maintenance procedures, the vendor manual, completed surveillance tests, and battery replacement practices were also reviewed to verify that the emergency lighting was being maintained in a manner that would ensure reliable operation.

Enclosure

7 Findings No findings of significance were identified .

.10 Cold Shutdown Repairs

a. Inspection Scope

. The team verified that the licensee had dedicated repair procedures, equipment, and materials to accomplish repairs of components required for cold shutdown which might be damaged by the fire to ensure cold shutdown could be achieved within the time frames specified in their design and licensing bases. The team verified that the repair equipment, components, tools, and materials (e.g. pre-cut cables with prepared attachment lugs) were available and accessible on site.

b. Findings No findings of significance were identified .

.11 Compensatory Measures

a. Inspection Scope The team verified that compensatory measures were in place for out-of-seryice, degraded or inoperable fire protection and post-fire safe shutdown equipment, systems, or features (e.g. detection and suppression systems and eqUipment, passive fire barriers, or pumps, valves or electrical devices providing safe shutdown functions or capabilities). The team also verified that the short term compensatory measures compensated for the degraded function or feature until appropriate corrective action could be taken and that the licensee was effective in returning the equipment to service in a reasonable period of time.

b. Findings No findings of significance were identified .

. 12 Large Fires and Explosions Mitigation Strategies

a. Inspection Scope The team reviewed the licensee's preparedness to handle large fires or explosions by reviewing four mitigating strategies to verify they continue to meet operating license conditions 2.C.(21) for Unit 1 and 2.C.(9) for Unit 2 by determining that:

,0 Procedures are being maintained and adequate;

'0 Equipment is properly staged and is being maintained and tested; and,

° Station personnel are knowledgeable and can implement the procedures.

Enclosure

8

b. Findings No finding s of significance were identified.

4. OTHE R ACTIVITIES lOA]

40A2 Identification and Resolution of Problems

.01 Corrective Actions for Fire Protection Deficiencies

a. Inspection Scope and post-fire safe The team verified that the licensee was identifying fire protection into the corrective action shutdown issues at an appropriate threshold and entering them to verify that the licensee program. The team also reviewed a sample of selected issues had taken or planned appropriate corrective actions.

ated with the Additionally, the team reviewed several Issue Reports (IRs) associ operat ions (MSO) scenarios that uses licensee's review of circuits for multiple spurious for Post-F ire Safe Shutdown the guidance provided in NEI 00-01, Revision 2, "Guidance Protec tion for Nuclear Circuit Analysis" and Regulatory Guide 1.189, Revision 2, "Fire Power Plants."

Specific IRs reviewed by the }eam are listed in theattachment.

b. Findings No findings of significance were identified.

scenarios for further The team determined that the licensee had identified several MSO tive action program review . The licensee placed the identified scenarios into their correc measu res prior to the May 2, 2010.

and implemented alternate compensatory 40A6 Meetings, Including Exit Exit Meeting Summary Maguire, Site Vice The team presented their preliminary inspection results to Mr. William the site staff at an exit President - Limerick Generating Station, and other members of ation was include d in this inspection meeting on May 28, 2010. No proprietary inform report.

ATTACHMENT: SUPPLEMENTAL INFORMATION Enclosure

A-1 ATTACHMENT SUPPLEMENTAL INFORMATION KEY POINTS OF CONTACT Licensee Personnel M. Ajmara, Nuclear Oversight S. Bobyock, Engineering Programs Manager J. Brittain, Fire Protection Engineer F. Burzynski, Fire Marshal E. Callan, Plant Manager F. Coffey, Operations Support Manager G. Curtain, Fire Protection Engineer P. Gardner, Director Operations R. Harding; Regulatory Assurance J. Hunter, Manager Reg. Assurance S. Johnson, Assistant Plant Manager C. Markle, Assessment Specialist W. Maguire, Site Vice President - LGS T. Moore, Director of Engineering C. Pragman, Exelon Corporate Fire Protection R. Rhode, Operator Instructor C. Rich, Director Work Management S. Soerun,Safe Shutdown Engineer M. Taylor, Exelon Corporate Fire Protection J. Rogge, Chief, Engineering Branch 3, Division of Reactor Safety W. Cook, Senior Reactor Analyst, Division of Reactor Safety E. DiPaolo; Senior Resident Inspector, Limerick Generating Station P. McKenna, Resident Inspector (Acting), Limerick Generating Station LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened NONE Opened arid Closed NONE Attachment

A*2 Closed NONE Discussed NONE LIST OF DOCUMENTS REVIEWED Fire Protection Licensing Documents LGS, SER (NUREG 0991, 8/1983)

LGS, SSER2 LGS, SSER4 ,

LGS UFSAR, Section 9.5, Other Auxiliary Systems, Fire Protection LGS UFSAR, Section 9A, Fire Protection Evaluation Report Design Basis Documents L*S*01B, Miscellaneous DC Systems, Rev. 2 L*S*51, Fire Protection System, Rev. 6 L*T*10, Fire Safe Shutdown, Rev. 11

\

Calculations/Engineering Evaluation Reports Comparison of Performance for Marauder 95 gpm Vs 125 gpm, 1*1/2" 100 Feet Rubber Lined Hose, July 2, 1997 Comparison of Performance for Marauder 95 gpm vs 125 gpm, 1*3/4" 100 Feet Rubber Lined Hose, July 2,1997 EAS*26*0489, Limerick Generating Station Units 1 and 2 Safe Shutdown Analyses for Fire Events, 5/89 ECR LG 97*00334, Hose Reels Missing Flow Orifices ECR LG*97*00855, Hose Reels Missing Flow Orifices ECR LG 98*00131, Modification P00736*2: Upgrade Thermolag /1 Hr Rating, Rev. 2 ECR LG 99*00484, Modification P00736S*1 & 2, New Sprinkler Systems (T*lag Reduction)

ECR LG 09*00317, Extent.of Condition from IR 843591 ECR LG 09*00369, CDBI FASA 15*Minute Ops Action in Flood PRA Not Achievable LEAF*0011, Fire Area 2,13.2 kV Switchgear Room , Localized Suppression, Rev. 0 LEAF*0021, Qualification of 3 Hour Darrnatt KM*1 Fire Barrier System 02*01 in Accordance with NCR Generic Letter 86* 10,* Supplement 1, Rev. O*

LF*0011, Hose Station Hydraulic Analysis LF*0016*002, Fire Area 002 Fire Safe Shutdown Analysis, Rev. 1 LF*0016*007, Fire Area 007 Fire Safe Shutdown Analysis, Rev. 0 LF*0016*022, Fire Area 022 Fire Safe Shutdown Analysis, Rev. 1 LF*0016--067W, Fire Area 067W Fire Safe Shutdown Analysis, Rev. 0 LF*0016*067E, Fire Area 067E Fire Safe Shutdown Analysis, Rev. 0 LT*0021, Hydraulic Analysis of the Limerick WP*124 Suppression System, Rev. 0 NE*C*420*1, Determination of 4kv Switchgear Motor Protection, Rev. 7 Attachment

A-3 NE-294, Specification for Post-Fire Safe Shutdown Program Requirement for Limerick, Rev. 3 6900E.02, Safeguard Auxiliary System - Phase Overcurrent Relay Selection and Coord., Rev. 8 690DE.D5B, LGS Units 1 & 2 Determination of 4kv Switchgear Motor Protection, Rev. 7 690DE.11, LGS Units 1 & 2 Load Center Circuit Breakers - Overcurrent Trip Devices, Rev. 8 .

Procedures CC-AA-2D9, Fire Protection Program Configuration Change Review, Rev. 1 OP-AA-2D1-DD2, Fire Reports, Rev. 4 .

OP-AA-2D1-DD3, Fire Drill Performance, Rev. 11 OP-AA-2D1-DD4, Fire Prevention for Hot Work, Rev. 8 OP-AA~2D1-DD5, Fire Brigade Qualification, Rev. 9 OP-AA-2D1-DD7, Fire Protection Impairment Control, Rev. 6 OP-AA-2D1-DD9, Control of Transient Combustible Material, Rev. 10.

ST-6-022-951-D, Fire Hose Station Visual Inspection, Rev. 2 Operations Procedures ARC-MCR-DD6 E4U, REAC I EL 253 NEUT MONITOR, Rev. 2 ARC-MCR-DD6 J2L, CONT EL 269 Control Room, Rev. 3 ARC-MCR-DD6 J2U, CONT EL 217 SWGR I & II, Rev. 1 GP-3, Normal Plant Shutdown, Rev. 130.

GP-3 Appendix 1, Establishing Cold Shutdown, Rev. 39 SE-1, Remote Shutdown, Rev. 63 SE-1-1, Protected Depressurization Control (Long Term Operation), Rev. 12 SE-1-2, Protected Power Source, Rev. 11 SE-1-3, Protected Ventilation Source, Rev. 15 SE-8, Fire, Rev. 37 T-1DO, LGS Trip Procedure, SCRAM/SCRAM Recovery, Rev. 17 1FSSG-3D02, 13 KV Switchgear Area, U-1, Rev. 6 2FSSG-3002, 13 KV Switchgear Area, U-2, Rev. 5 2FSSG-3007, Corridor (4 KV), Rev. 6 1FSSG-3D22, Fire Area 0.22 Fire Guide, Rev. 7 2FSSG-3067E, Safeguard System Access Area East, Rev. 4 2FSSG-3037W, Safeguard System Access Area West, Rev. 4 Large Fires and Explosions Mitigation Strategies Documents LS-AA-126~1D05, Dated May 9,20.10..

RT-6-DD-913-0, Rev. 5 SE-8, Rev. 36 SE-23, Rev. 20.

S1DD.1.A, Rev. 6 T-216, Rev. 16 TSG-4.1, Rev. 8 TSG-4.2, Rev. 2 Attachment

A-4 Completed Tests/Surveiliances RT-6-000-900-0, Inspection of Safe Shutdown Equipment, Rev. 23, Completed 1/24/10 RT-6-10S-300-0, Fire Safe Shutdown Emergency Lighting Unit (ELU) Operability Verification, Rev. 16, Completed 3/20/10 RT-6-1 OS-300-1, Fire Safe Shutdown Emergency Lighting Unit (ELU) Operability Verification, Rev. 17, Completed 4/1/10

• RT-6-1 OS-300-2, Fire Safe Shutdown Emergency Lighting Unit (ELU) Operability Verification, Rev. 17, Completed 1/23/10 ST-2-088-320-0, Remote Shutdown System ESW and RHRSW Operability Test, Rev. 15, Completed 08/05/09 ST-2-08S-320-1, Remote Shutdown System RCIC Operability Test, Rev. 11, Completed 12/04/08 ST-2-0SS-321-1, Remote Shutdown System DIV 1 RHR OperabilityTest, Rev. 1S, Completed 12/29/0S ST-2-0SS-321-2, Remote Shutdown System Div. 1 RHR Operability Test, Rev. 14, Completed 07/14109 ST-2-0SS-324-1, Remote Shutdown System Div 2 RHR Operability Test, Rev. 7, Completed 11/14/0S .

ST-2-08S-401-1, Remote ShutdownlAccident Monitoring Drywell Temperature and Suppression Chamber Temperature Calibration (TE-057-122, TE-057-125, TT-057-122, TI-057-122, TR-057-122), Rev. 12, Completed OS/03/09 ST-2-08S-402-1, Remote Shutdown Monitoring - RHR System Flow Calibration (FT-051-1N001, FY-051-1K011, FI-051-1R005), Rev. 12, Completed OS/12/09 .

ST-2-0Ss-403-1, Remote Shutdown Monitoring, RCIC System Flow Calibration (FT-049-1N003, FY-049-1 KOO 1, FI-049-1 R001-1), Rev. 9, Completed 06/02/08 ST-2-0SS-405-0, Remote Shutdown Monitoring - RHR Service Water Pumps Loop 'A' Calibration (PT-012-001A, PI-012-001A-1, PI-012-001A-2, PI-012-001A-3), Rev. 15,Completed 10/14/09 ST-2~OSS-41 0-1, Remote Shutdown System - Reactor Vessel Water Level Calibration (LT.042-1N010, LI-042-1R010), Rev. 10, Completed 03/14/08, 03/22/10 ST-2-088-410-2, Remote Shutdown System - Reactor Vessel Water Level Calibration

. (LT~042-2N01 0, LI-042-2R010), Rev. 4, Completed 03/23/09 ST-4-022-920-2, Fire Rated Assembly Inspection, Completed April 5, 2009 ST-4-022-921-1, Fire Damper InspectionlFunctional Test, Completed April 3, 2009 ST-4-022-922-2, Fire Penetration Test Sample Visual Inspection, Completed April 1, 2009 ST-4-022-924-2, Encapsulated Raceway Inspection, Completed November 21, 2008 ST-4-041-470-1, Cyclic Test Of Main Steam Safety Relief Valve Solenoid and Air Operator Assemblies, Rev. 3, Completed 04/06/10 ST-6-08S-301-1, Suppression Pool Spray Remote Shutdown*System Valve Test, Rev. 0, Completed 12/30108 ST-6-088-321-1, Remote Shutdown System D11 Safeguard Breaker Operability Test, Rev. 3, Completed 03/31/10 1P-13.2, Preoperational Test Procedure, Fire Protection C02 System, Startup Subsystem 13C, Rev. 0 Attachment

A-5 Quality Assurance IQA) Audits and Self Assessments' FASA Self-Assessment Report, Limerick Triennial Fire Protection Inspection, 2010 NOSA-LlM-08-09, Limerick Fire Protection Program Audit Report, 6/9-20/08 System Health Reports 4'h Quarter 2009, LGS Fire Protection Fire Safe Shutdown Program s

1 ' Quarter2010, LGS Fire Protection Fire Safe Shutdown Program Drawings and Wiring Diagrams E-15, Single Line Meter and Relay Diagram 4kv Safeguard Power System 1 Unit, Rev. 29 E-27, Single Line Meter and Relay Diag. MCC Load Tab. D214-R-G1 and D224-R-G1 Reactor Area, Rev. 31 E-30, Sht. 3, Single Line Diagram Instrumentation AC System 1 Unit, Rev. 26 E-31 , Sht. 3, Single Line Diagram Instrumentation AC System 2 Unit, Rev. 19 E-33, Sht. 1, Single Line Meter and Relay Diagram 125/250VDC System Unit 1, Rev. 44 E-34, Sht. 1, Single Line Meter and Relay Diagram 125/250VDC System 2 Unit, Rev. 37 E-55, Sht. 1, Single Line Meter and Relay Diagram MCC Load Tabulation D114-R-G, D124-R-G Reactor Area Safeguard MCC, Rev. 51 .

E-67, Sht. 1, Single Line Meter and Relay Diagram MCC Load Tabulation D214-R-G and D224-R-G Reactor Area, Rev. 44 E-68, Sht. 1, Single Line Meter and Relay Diagram MCC Load Tabulation D214-R-C, D224-R-C, D234-E & D244-R-E Reactor Area, Rev. 38 E-102, Sht 1, Schematic Block Diagram RHR System 1 & 2 Units, Rev. 22 E-102, Sht. 2, Schematic Block Diagram RHR System 1 & 2 Units, Rev. 33 E-105, Sht. 2, Schematic Block Diagram RCIC System 1 & 2 Units, Rev. 28 E-115, Sht. 1, Schematic Block Diagram PGCC SITS Cables 1 & 2 Units and Common, Rev. 34 E-115, Sht. 2, Schematic Block Diagram PGCC SITS Cables 1 & 2 Units and Common, Rev. 14 E-115, Sht; 3, Schematic Block Diagram PGCC SITS Cables 1 & 2 Units and Common, Rev. 27 E-115, Sht. 4, Schematic Block Diagram PGCC SITS Cables 1 & 2 Units and Common, Rev. 21 E-115, Sht: 5, Schematic Block Diagram PGCC SITS Cables 1 & 2 Units and Common, Rev. 32 E-115, Sht. 6, Schematic Block Diagram PGCC SITS Cables 1 & 2 Units and Common, Rev. 20 E-325, Sht. 1, Schematic Diagram Cooling Water Shutoff Valves to Service Water and ESW - 1

. & 2Units, Rev. 10 E-361 , Sht 1, Schematic Diagram RHR Service Water Pumps Common, Rev. 28 E-371 , Sht. 1, Schematic Diag. RHR Heat Exch. Tube Side Inlet MOV's - 1 & 2 Units, Rev. 13 E-10024, Block Diagram Radio and Distributed Antenna System, Rev. 1 M-1-E11-1040-E-04S, Sht. 2, Elementary Diagram Residual Heat Removal System, Rev. 0 M-1-E51-1040-E-032, Sht. 1, Elementary Diagram Reactor Core Isolation, Rev. 13 M-1-E51-1040-E-032, Sht. 2, Elementary Diagram Reactor Core Isolation, Rev. 0 737-D-VC-00039, Sheets 1-16, 3 Hour Darmatt KM-1 Barrier 02-01 Arrangement, Rev. 0 S031-C-756, Control Area, Key Plans -Interior Walls EI1S0'-0" to EI332'-0" area S, Rev. 21 S031-E-28, Spec. for 600 Volt Power, Control and Inst. Cable for The LGS Units 1 & 2, Rev. 1S S031-FSC~19S-22-8, Cable tray Thru Fire Barrier S031-FSC-19S-1652-4, Penetration Seal Design 8031-M-1-C61-1050-E-012.25, Sht. 2, Elementary Diag. Remote Shutdown System, Rev. 17 Attachment

A-6 e Shutdown System, Rev. 13 8031-M-1-C61-1 050-E-014.13, Sht. 4, Elementary Diag. Remot m Residu al Heat Removal System, Rev. 33 8031-M-1-E11-1040-E-016, Sht. 1, Elementary Diagra Wall No. 68 Thru 75 & .102 Thru 8031-PSA-763, Control Room Area 8 Interior Wall Elevations, 04,Re v.16

• Piping and*lnstrumentation Diagrams Common), Rev. 84 8031-M-11, Sht. 2, P&ID, Emergency Service Water (Unit 1 and Servic e Water (Common), Rev. 69 8031-M-12~ Sht. 1, P&ID, Residual Heat Removal n (Unit 2), Rev. 21 8031-M-42; Sht. 3, P&ID, Nuclear Boiler Vessel Instrumentatio 2), Rev. 48 8031-M-49, Sht. 2, P&ID, Reactor Core Isolation Cooling (Unit 8031-M-50, Sht. 1, PI&D, RCIC Pump Turbine, Rev. 35 65 8031-M-51, Sht 1, P&ID, Residual Heat Removal (Unit 1), Rev.

Heat Remov al (Unit 1), Rev. 66 8031-M-51, Sht. 2, P&ID, Residual 30 8031-M-51, Sht. 5, P&ID, Residual Heat Removal (Unit 2), Rev.

al (Unit 2), Rev. 23 8031-M-51, Sht 6, P&ID, Residual Heat Remov n, Rev. 53 8031-M-55~ Sht. 1, PI&D, High Pressure Coolant Injectio 8031-M-56, Sht. 1, PI&D, HPCI Pump Turbine, Rev. 4 Vendo r Manuals Technical Service Parts List Akron Firefighting Equipment Electrical Assault Nozzle, Style 4815 Assault Nozzle Akron Firefighting Equipment Operating Instructions, Electrical

\ Assau lt Specification and Technical Data Exide Lightguard F100/F100RT, ELU Vendor Manual Marauder Nozzles Specification Sheet Pre-Fire Plans F-A-33 6, 13.2 KV Switchgear Room 336 (EI. 217'),R ev. 12 F-A-437, Common, Corridor 437 (EI. 239'), Rev. 9 F-A-449, Common, Unit 1 Cable Spreading Room (EI. 254'), Rev. 12 10 F-R-370, Unit 2 Safeguards System Access Area Room 370 (EI. 217'), Rev.

Fire Drills and Critiques F-R-181, 2B Core Spray Pump Room, Completed 5/21/09 9

F-R-402, U1 Reactor Enclosure, Room 402, Completed 2/4/09 and 5/16/0 F-R-475, U2 Reactor Enclosure, Room 475, Completed 2/12/09 F-R-500, U1 Reactor Enclosure, Fire Area 47, Completed 5/12/09 Fire Brigade Training FBP01, Introduction/Orientation, Rev. 6 FBP02, Protective Clothing, Rev. 5 FBP04; Fire Behavior & Essentials, Rev. 9 FBP05, Ventilation, Rev, 6 FBP07, Hose Streams, Appliances, Tools, Rev. 6

. FBP08 , Rescue, Rev. 7 Attachment

A-7 FBP09, Extinguishers and Agents, Rev. 8 FBP11, Tactics and Strategy, Rev. 7 FBP13, Communications, Rev. 3 FBP14, Building Construction/Awareness, Rev. 6 FBP15, Pre-Fire Plans, Rev. 6 FBP17, Foam/Multi-Agent Operations, Rev. 1

. IMS-01, Incident Management System, Rev. 2 Operator Safe Shutdown Training JPM Number LLOJPM0207, Start OB ESW Pump from D12 Switchgear for SE-06, Rev. 9 JPM Number LLOJPM0224, Supply Alternate DC Control Power for ADS, Rev. 10 JPM Number LLOJPM0261, Initiate Reactor SCRAM and MSIV Closure from AER Using SE-1 (Alternate Path), Rev. 7 JPM Number LLOJPM0267, Alignment of Equipment for Manual Operation of LPCI, Rev. 4 JPM Nurnber 0250, Supply Emergency Power to RCIC Inboard Isolation Valve, Rev. 8 LSTS-4001, Fire with Unusual Event Declaration/Grid Emergency, Rev. 0 Transient Combustible Evaluations A1744917-38 A1744917-39 A1744917-40 A1744917-'41 A1744917-42 Miscellaneous Documents BISCO Test Report No. 748-41, Fire Test Configuration for a Three Hour Rated Fire Seal Control Room Shift Complement for Fire Brigade & Safe Shutdown Operators 4/26-29/2010 Fire System Impairment Log, 4/23/10 INDMS - Cable Location Report INDMS - Safe and Alternate Shutdown Logics

. LGS Maintenance Rule Scope & Performance Monitoring, Emergency Lighting (8 Hour Packs)

Limerick Fire Induced MSO 6 Month Project Strategy NE-294, Specification for Post-Fire Safe Shutdown Program Requirements at LGS, Rev. 3 SDOC 831,D-VC-0006, Test Report on Three-Hour Fire Test and Five Minute Hose Stream Test on PECO Energy Test Slab 4, Rev. 0 SDOC 737-D-VC-00050, Fire Endurance Test of Thermo-Lag 330-1 Fire Protection Envelopes on 12' and 14" Cable Trays and 1", 2" and 5" Conduits (Using Various Upgrades of Thermo-Lag 770-1, Rev. 0 SDOC 831cD-VC-00013, Test Report for a 1 Hour Fire Test on Darmatt KM1 Fire Protection System for a Representative Site Configuration of a 24"X24X18 Junction Box, Rev. 0 SDOC 831-D-VC-0015, Test Report for a 3 Hour Fire Test on Darmatt KM1 Fire Protection System for Electrical Circuit Systems to ASTM E119 NRC GL 86-10 Supplement 1, Rev. 0 SDOC 831-D-VC-0032, Report On A Three Hour Fire and 5 Minute Water Hose stream Test on

%" and 5" Diameter Generic Conduit Insulated with Darmatt KM1, Rev. 0 Attachment

A-8 SDOC 831-D-VC-0044, Report on the Three Hour Fire Test 15 Minute Water Hose Test on Darmatt KM1 Fire Protection System for Protecting %" and 4" Diameter Rigid Steel Conduits at Braidwood and Byron NPS, Rev. 0 VU1200-TD-003, PECO Energy LGS Thermo-Lag Fire Endurance Qualification Report, Rev. 3

. Utilizing BISCO SF-20 Silicone Foam (Dow Coming 3-6548)

White Paper, Description of Fire Safe Shutdown Radio System 8031-E-28, Specification for 600 Volt Power, Control and Instrumentation Cable for the LGS Units 1 & 2 for the Philadelphia Electric Company, Rev. 18 Issue Reports 0617637 0793229 0843591 0884947 0656185 0993022 1041652# 1061665 1061908# 1061914# 1061920# 1061926#

1061929# 1061935# 1061942# 1061950# 1061965# 1061996#

1061999# 1062012# 1062016# 1062022# 1062025# 1062030#

1062036# 1062040# 1062048# 1062092# 1062102# 1062110#

1062116# 1062121# 1062140# 1062145# 1062150# 1062155#

1062163# 1062172# 1062181# 1062187# 1062190# 1062195#

1062197# 1062200# 1062503# 1062507# 1062511# 1063220*

1063227* 1063255* 1063262* 1063778* 1068483* 1068511*

1069300* 1069527* 1069560* 1073033* 1073177* 1073304 1073485* 1073587* 1073719* 1074128* 1074131* 1074132*

1074139*

\

1. Licensee identified during multiple spurious operations review of RG 1.189, Rev. 2 & NEI 00 01, Rev. 2. Altemate compensatory actions were implemented accordingly.

• NRC identified during this inspection .

. Action Requests A1031688 A1354849 A1361986 A1397453 A1483451 A1698208 A1702750 00617637 00771615 00921985 Work Orders R0564411 R0812059 R0827448 R0856144 R0918809 R1123936 Attachment

A-9 LIST OF ACRONYMS ADAMS Agencywide Documents Access and Management System AC Altemating Current BTP Branch Technical Position CFR Code of Federal Regulations CMEB Chemical Engineering Branch CO2 Carbon Dioxide DRS Division of Reactor Safety EGM Enforcement Guidance Memorandum FA Fire Area FHA Fire Hazards Analysis FPP Fire Protection Program FSSG Fire Safe Shutdown Guide HPCI High Pressure Coolant Injection INDMS Integrated Nuclear Data Management System IP Inspection Procedure IPE Individual Plant Examination IPEEE Individual Plant Examination of External Events IR Issue Report JPM Job Performance Measures LGS Limerick Generating Station MSO Multiple Spurious Operation NEI Nuclear Energy Institute NFPA National Fire Protection Association NRC Nuclear Regulatory commission PAR Publicly Available Records P&ID Piping and Instrumentation Drawing QA Quality Assurance RCIC Reactor Core Isolation Cooling RHR Residual Heat Removal RHRSW Residual Heat Removal Service Water SER Safety Evaluation Report UFSAR Updated Final Safety Analysis Report Attachment

UNITED STATES NUCLEAR REGULATORY COMMISSION REGION I 475 ALLENDALE ROAD KING OF PRUSSIA, PA 19406-1415 March 10, 2009 Ms. Donna Cuthbert, Vice President Alliance for a Clean Environment P.O. Box 3063 Stowe, PA 19464

Dear Ms. Cuthbert:

I have attached responses to your letters of December 15, 2008, and January 12, 2009, dealing with radioactive waste and fire protection issues at Limerick Generating Station, respectively.

I have not responded point-by-point to the questions you posed, but rather described the information in general, and provided publicly available references for more specific, detailed answers.

The documents referenced in the attachments can be accessed through the NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRqs document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html(the Public Electronic Reading Room).

I trust that this information is responsive to your needs. If you should have any further questions or require additional information, please do not hesitate to contact us.

Sincerely, IRA!

Paul G. Krohn, Chief Projects Branch 4 Division of Reactor Projects Docket Nos. 50-352, 50-353 License Nos. NPF-39, NPF-85 Attachments: As stated Enclosure 7

Ms. Donna Cuthbert, Vice President Alliance for a Clean Environment P.O. Box 3063 Stowe, PA 19464

Dear Ms. Cuthbert:

I have attached responses to your letters of December 15, 2008, and January 12, 2009, dealing with radioactive waste and fire protection issues at Limerick Generating Station, respectively.

I have not responded point-by-point to the questions you posed, but rather described the information in general, and provided publicly available references for more specific, detailed answers.

The documents referenced in the attachments can be accessed through the NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRC's document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html(the Public Electronic Reading Room).

I trust that this information is responsive to your needs. If you should have any further questions or require additional information, please do not hesitate to contact us.

Sincerely, IRA!

Paul G. Krohn, Chief Projects Branch 4 Division of Reactor Projects Distribution w/encl D. Lew, DRP P. Krohn, DRP R. Barkley, ORA N. Seiler, DRP, RI D. Roberts, DRS J. Rogge, DRS R. Fuhrmeister, DRP L. Pinkham, Resident OA J. Clifford, DRP D. Screnci, ORA T. Setzer, DRP P. Bamford, PM, NRR E. Cobey, DRS N. Sheehan, ORA E. DiPaolo, DRP, SRI E. Miller, NRR, Backup PM SUNSI REVIEW COMPLETE: _..!.P~G~K~_ (Reviewer's Initials)

DOCUMENT NAME: G:IDRPIBRANCH4IResponses to 'Alliance for a Clean Environment'IACE Response 09-01 R1.doc After declaring this document "An Official Agency Record" it will be released to the Public.

To receive a copy of this documen~ indicate in the box: "C~ =Copy without attachment/enclosure ~En =Copy with attachment/enclosure "N" =No copy OFFICE RI/ DRP I RI/ DRS I RI/ DRS I RIIDRP I NAME RFuhnmeister JWhite/EHG for JRogge/KLG for PKrohn DATE 03/06/09 03/09/09 03/06/09 03/10/09 OFFICIAL RECORD COPY

Attachment 1 NRC Response to ACE Letter of December 15. 2008 Multiple questions relating to Radioactive Waste Disposal at Limerick Generating Station

RESPONSE

All nuclear power plant licensees are required to annually provide effluent release data generated during their operations to the U.S. Nuclear Regulatory Commission (NRC). This data includes details on disposing of solid, liquid, and gaseous waste.

For the Limerick Generating Station, the data, you requested, can be accessed through the NRC Public Document Room or from the Publicly Available Records (PARS) coniponent of the NRC's document system (ADAMS).

The Annual Radioactive Effluent Release Reports can be reviewed for calendar years 2007 (ML081260683), 2006 (ML071210611), 2005 (ML061250292), 2004 (ML051230219), and 2003 (ML041180432). In each report, specific data regarding the types, quantities, and destinations for solid radioactive waste shipments can be found in Appendix B of these reports (for example, page 25 in the 2007 report, ML081260683). Data regarding liquid and gaseous releases can be found in the tables located in Appendix A (for example, page 11 in the 2007 report, ML081260683).

As part of our reactor oversight program, routine inspections are conducted of the Limerick effluent treatment/monitoring programs, radioactive waste processing/transportation programs, and radiological environmental monitoring program to assure that Limerick complies with Technical Specifications, applicable regulations, and regulatory commitments. These inspections are conducted in accordance with inspection procedures within the reactor oversight program, specifically: 71122.01, "Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems" (ML083180411) conducted annually; 71122.02, "Radioactive Material Processing and Transportation" (ML020730765) conducted biennially; and 71122.03, "Radiological Environmental Monitoring Program (REMP)*and Radioactive Material Control Program" (ML020730768) also conducted biennially. From these inspections, Limerick was found to be in compliance with the relevant requirements. Additionally, it was determined that oil has not been incinerated for at least the past five (5) years at the station.

With respect to your questions regarding the renewal application for the Limerick Title V Operating Permit, you should direct your questions to the Commonwealth of Pennsylvania, Department of Environmental Protection, Air Quality Program. Please note that the Title V permit addresses Emission Limitations, Testing/Monitoring/Record Keeping/Reporting requirements for non-radiological matter (oil) incineration (waste derived liquid fuels typically consist of reclaimed/reprocessed oils - for example, used motor oil - and do not normally contain byproduct radioactive material from nuclear power plant operation). Only the NRC, in coordination with the US Environmental Protection Agency, regulates radiological wastes and effluents. Should Limerick decide to conduct oil incineration, the oil would be analyzed for radioactive contaminants, and any releases would be reported to the NRC in the Annual Radioactive Effluent Release Report.

1

Information related to the costs of processing and disposal of radioactive materials is not within the purview of the USNRC inspection program. This information, associated with operating costs and not nuclear safety, should be requested from the facility licensee.

2

Attachment 2 NRC Response to ACE letter of Januarv 12, 2009 Question: Is Limerick Nuclear Power Plant in Complete Compliance with All Fire Safety Rules?

Response

The Nuclear Regulatory Commission (NRC) has determined that Limerick is in compliance with all fire safety rules because of the combined licensing. inspection. and enforcement activities we perform, The NRC has established a solid regulatory framework to regulate fire safety. which includes periodic inspections in order to identify significant issues of non-compliance and ensure timely corrective action to restore compliance when needed.

For your information. the NRC conducts the following routine Fire Protection inspections at the Limerick Generating Station. The results of these inspections are available for viewing in ADAMS as mentioned in the cover letter.

Triennial Fire Protection Team Inspection Every three years. a team composed of a fire protection inspector. a reactor operations inspector. and an electrical inspector conduct a review of the defense-in-depth used by the facility to mitigate the consequences of a fire. This inspection is conducted in accordance with inspection procedure (IP) 71111.05T (ML061140176) and includes apprOXimately 200 person"hours of direct on-site inspection. This inspection targets specific risk-significant areas of the facility for a detailed review. This review includes the design of the post-fire safe shutdown equipment for the target areas (including control and power cables). protection of the post-fire safe shutdown equipment (including control and power cables) from the effects of fires. and operating procedures for achieving stable safe shutdown conditions in the event of a sig nificant fire in the target areas which damages equipment and requires a plant shutdown. The inspection also includes a walkthrough of one of the procedures (or portions thereof) for verifying post-fire shutdown capabilities.

The most recent triennial fire proteCtion inspection was conducted at Limerick in July and August of 2007. The inspection report was issued August 27. 2007. and is available in ADAMS under ML072400443.

Annual Resident Fire Protection Review Every year. a resident inspector evaluates performance of the on-site fire brigade by observing one or more fire brigade drills. The inspection is conducted in accordance with IP 71111.05AQ (ML080350272) and evaluates fire brigade performance, fire brigade equipment. command and control functions. availability and condition of manual fire-fighting equipment. and the Iicensee's assessment of performance through the drill critique.

The most recent fire brigade drill observation was conducted at Limerick in December 2008. It is documented in Section 1R05 of inspection report 2008-005. in ADAMS under ML090330638.

1

Quarterly Resident Fire Protection Review Every quarter, a resident inspector tours four to six risk-important areas of the plant to assess defense-in-depth aspects of the fire protection program. This review is also conducted in accordance with IP 71111.0SAQ. The defense-in-depth aspects of the program include passive fire barriers (such as walls and penetration seals), active fire barrier components (such as doors and dampers),

material condition of fire-fighting equipment and systems, and control of combustible materials.

The four quarterly reviews for 2008 are documented in Section 1ROS of inspection reports 2008-002 (ML081270SS1), 2008-003 (ML082261341), 2008-004 (ML083181209), and 2008-005 (ML090330638).

Notwithstanding your specific Limerick questions, on a national level, the NRC staff continues to evaluate fire protection issues with potential generic applicability. These issues include unapproved manual operator actions, multiple spurious operations due to fire-induced failures, and fire barrier adequacy; none of which currently affect Limerick .

compliance with all fire safety regulations.

2

UNITED STATES NUCLEAR REGULATORY COMMISSION REGION I 475 ALLENDALE ROAD KING OF PRUSSIA, PA 19406-1415 May 6, 2008 Mr. Charles G. Pardee Chief Nuclear Officer (CNO) and Senior Vice President Exelon Generation Company, LLC Chief Nuclear Officer (CNO)

AmerGen Energy Company, LLC 200 Exelon Way Kennett Square, PA 19348

SUBJECT:

LIMERICK GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000352/2008002 AND 05000353/2008002

Dear Mr. Pardee:

On March 31, 2008, the U. S. Nuclear Rkgulatory Commission (NRC) completed an inspection

. at your Limerick Generating Station Units 1 and 2. The enclosed integrated inspection report documents the inspection results which were discussed on April 10, 2008, with Mr. C. Mudrick and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

This report documents three findings of very low safety significance (Green). One of these findings was determined to involve a violation of an NRC requirement. However, because of the very low safety significance and because it is entered into your corrective action program (CAP),

the NRC is treating the finding as a non-cited violation (NCV), consistent with Section V1.A.1. of the NRC Enforcement Policy. If you contest the NCV in this report, you should provide a response within 30 days of the date of this inspection report, with basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-001; with copies to the Regional Administration, Region 1; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-001; and the NRC Resident Inspector at the Limerick facility.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the Enclosure 8

Mr. C. Pardee 2 NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRC's document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.govlreading-rm/adams.html(the Public Electronic Reading Room).

Sincerely, IRA!

Paul G. Krohn, Chief Projects Branch 4 Division of Reactor Projects Docket Nos: 50-352, 50-353 License Nos: NPF-39, NPF-85

Enclosure:

Inspection Report 05000352/2008002 and 05000353/2008002 w/AUachment: Supplemental Information cc w/encl:

C. Crane, Executive Vice President and Chief Operating Officer, Exelon Generation M. Pacilio, Chief Operating Officer, Exelon Generation Company, LLC C. Mudrick, Site Vice President - Limerick Generating Station E. Callan, Plant Manager, Limerick Generating Station R. Kreider, Regulatory Assurance Manager R. DeGregorio, Senior Vice President, Mid-Atlantic Operations K. Jury, Vice President, Licensing and Regulatory Affairs P. Cowan, Director, Licensing B. Fewell, Associate General Counsel Correspondence Control Desk D. Allard, Director, PA Department of Environmental Protection J. Johnsrud, National Energy Committee, Sierra Club Chairman, Board of Supervisors of Limerick Township J. Powers, Director, PA Office of Homeland Security R. French, Director, PA Emergency Management Agency

Mr. C. Pardee 3 NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRC's document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.govlreading-rm/adams.html(the Public Electronic Reading Room).

Sincerely, Paul G. Krohn, Chief IRA!

Projects Branch 4

• Division of Reactor Projects Docket Nos: 50-352, 50-353 License Nos: NPF-39, NPF-85 Distribution w/encl: (via email) C. Bickett, DRP, Resident Inspector S. Collins, RA L. Pinkham, Resident OA M. Dapas, DRA S. William, RI, OEDO D. Lew, DRP H. Chemoff, NRR J. Clifford, DRP P. Bamford, PM, NRR P. Krohn, DRP J. Hughey, PM, Backup R. Fuhrmeister, DRP ROPreports@nrc.gov T. Setzer, DRP Region I Docket Room (with concurrences)

E. DiPaolo, DRP, Senior Resident Inspector SUNSI REVIEW COMPLETE: _--,-P-"G~K>-_(Reviewer's Initials)

DOCUMENT NAME: G:\DRP\BRANCH4\DRAFT INSPECTION REPORTS FOR BR 4 leOR 2008\1ST QTR 2008 DRAFT REPORTS\UM\UM 2008-002 REV 3.DOC ML081270551 After declaring this document "An Official Agency Record" it will be released to the Public To receive a copy of this document, indicate in the box: °C" = Copy without attachment/enclosure liE" = Copy with attachment/enclosure "Nil = No copy OFFICE RIIDRP I RI/DRP I RIIDRP I NAME EDiPaolol PGK for RFuhrmeister/RF PKrohn/PGK DATE 05/05108 05/06/08 05/06/08 OFFICIAL RECORD COpy

1 U.S. NUCLEAR REGULAt6kv COMMISSION REGION 1 Docket Nos: 50-352, 50-353 License Nos: NPF-39, NPF-85 Report No: 05000352/2008002 and 05000353/2008002 Licensee: Exelon Generation Company, LLC Facility: Limerick Generating Station, Units 1 & 2 Location: Sanatoga, PA 19464 Dates: January 1,2008 through March 31, 2008 Inspectors: E. DiPaolo, Senior Resident Inspector C. Bickett, Resident Inspector J. Caruso, Acting Senior Resident Inspector T. Moslak, Health Physicist J. Kulp, Reactor Inspector E. Gray, Senior Reactor Inspector E. Burket, Reactor Inspector (in-training)

C. Crisden, Reactor Engineer (in-training)

Approved by: Paul G. Krohn, Chief Projects Branch 4 Division of Reactor Projects Enclosure

2 TABLE OF CONTENTS

SUMMARY

OF FINDINGS ......................................................................................................... 3 REPORT DETAILS ..................................................................................................................... 5

1. REACTOR SAFETY ........................................................................................................... 5 1R01 Adverse Weather Protection ................................................................................... 5 1R04 Equipment Alignment ............................................................................................. 6 1R05 Fire Protection ......................................................................................................... 6 1R08 In-Service Inspection .............................................................................................. 7 1R11 Licensed Operator Requalification Program ........................................................... 8 1R12 Maintenance Effectiveness ..................................................................................... 9 1R13 Maintenance Risk Assessments and Emergent Work Control .............................. 10 1R15 Operability Evaluations ......................................................................................... 11 1R18 Plant Modifications ............................................................................................... 12 1R19 Post-Maintenance Testing .................................................................................... 13 1R20 Refueling and Other Outage Activities .................................................................. 13 1R22 Surveillance Testing ............................................................................................. 17

2. RADIATION SAFETY ....................................................................................................... 18 20S1 Access Control to Radiologically Significant Areas ............................................... 18

4. OTHER ACTiViTIES ......................................................................................................... 23 40A1 Performance Indicator (PI) Verification ......... ,....................................................... 23 40A3 Event Follow-Up ................................................................................................... 23 40A6 Meetings, Including Exit.. ....................................................................................... 24 SUPPLEMENTAL INFORMATION ......................................................................................... A-1 KEY POI NTS OF CONTACT .................................................................................................. A-1 LIST OF ITEMS OPENED, CLOSED, AND DiSCUSSED ....................................................... A-1 LIST OF DOCUMENTS REVIEWED ...................................................................................... A-2 LIST OF ACRONyMS .......................................................................................................... A-1 0 Enclosure

3

SUMMARY

OF FINDINGS IR 05000352/2008002, 05000353/2008002; 01/01/2008 - 03/31/2008; Limerick Generating Station, Units 1 and 2; Maintenance Effectiveness, Operability Evaluations, and Refueling and Outage Activities.

The report covered a three-month period of inspection by resident inspectors and announced inspections by regional reactor inspectors. Three green findings, one of which was determined to be a non-cited violation (NCV), were identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process (SOP)." Findings for which the SOP does not apply may be green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight," Revision 4, dated December 2006.

A. NRC-Identified and Self-Revealing Findings Cornerstone: Initiating Events

• Green. A self-revealing finding was identified for an inadequate maintenance procedure regarding electrical connections associated with the Unit 2A Main Transformer bushings. The procedure was not ciear as to the appropriate method to prepare the surface for an aluminum bushing terminal and did not provide adequate information on torque requirements and the use of anti-oxidant grease. This resulted in the failure of the bushing connection and a Unit 2 reactor scram on February 1, 2008. Exelon entered this issue into the corrective action program (CAP), performed repairs, and revised the procedure to reflect the appropriate information to successfully assemble the connection.

The issue is more that minor because it is associated with procedure quality attribute of the Initiating Events cornerstone and affected the objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. The inspectors evaluated the finding using Phase 1 of IMC 0609, Appendix A, "Significance Determination of Reactor Inspection Findings for At-Power Situations." This finding was determined to be of very low safety significance (Green) because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would be unavailable. (Section 1R12)

• Green. Inspectors identified a Green non-cited violation (NCV) of Technical Specification (TS) 6.8.1 for failure to promptly implement actions to recover the Unit 1 skimmer surge tank (SST) level during the 1R12 Unit 1 refueling outage. Prompt action by the operators would have prevented entrainment of the air into the residual heat removal (RHR) system, elevated radiation levels on the refuel floor, and subsequent entry into off-normal procedure ON-120, "Fuel Handling Problems."

Exelon entered this issue into their CAP for resolution.

This finding is more than minor because it affects the human performance attribute of the Initiating Events cornerstone and the objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during Enclosure

4

... shutdown as well as power operations. The inspectors evaluated this finding using IMC 0609, Appendix G, "Shutdown Operations Significance Determination Process,"

Attachment 1. This finding is of very low safety significance (Green) because the finding did not require quantitative assessment per Checklist 7 of Attachment 1 to IMC 0609 Appendix G. The reactor time-to-boil during this event was approximately 26 hours3.009259e-4 days <br />0.00722 hours <br />4.298942e-5 weeks <br />9.893e-6 months <br /> and adequate time was available to vent and restart the affected RHR pump in the Alternate Decay Heat Removal (ADHR) mode of operation .

Additionally, during the time that ADHR was secured, natural circulation provided reactor coolant flow. This finding has a human performance cross-cutting aspect in the area of work practices. Specifically, operators did not follow OP-AA-1 03-1 02, "Watchstanding Practices," in that they did not promptly implement actions required by the applicable alarm response procedure to recover SST level following receipt of the associated control room alarm (H.4(b)). (Section 1R20.3)

Cornerstone: Mitigating Systems

• Green. The inspectors identified a Green finding for failure to identify corrective actions for an adverse condition associated with unsatisfactory performance of a Unit 1 main turbine bypass valve following an automatic scram event on March 22, 2008. As a result, an appropriate operability determination was not performed and the issue was not considered by the Plant Operations Review Committee during a restart meeting on March 23, 2008. Exelon entered the issue into the CAP for resolution.

The finding was more than minor because it was associated with the equipment*

1 performance attribute of the Mitigating Systems cornerstone and affected the objective io ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was assessed using Phase 1 of IMC 0609, Appendix A, "Significance Determination for Reactor Inspection Findings for At-Power Situations," and determined to be of very low safety significance (Green) because the finding did not represent an actual loss of safety function of single train for greater than its TS allowed outage time. This finding has a cross-cutting aspect of Problem Identification and Resolution (PI&R) becauseExelon did not thoroughly evaluate the problem such that the resolution addressed the cause of the condition or the effect the condition had on system operability (P.1 (c>>.

(Section 1R15)

B. Licensee-Identified Violations None.

Enclosure

5 REPORT DETAILS Summary of Plant Status Unit 1 began the inspection period operating at full rated thermal power (RTP) and operated at full power until March 1, 2008, when the unit entered end-of-cycle coastdown operations. On February 29, 2008, operators commenced a shut down, from an initial power of 87 percent, for a planned refueling and maintenance outage (1R12). Operational Condition 5 (Refueling) was achieved on March 3, 2008. Following the completion of refueling and maintenance activities, operators commenced a reactor startup on March 19, 2008. During power ascension, Unit 1 automatically scrammed, from an initial power level of 87 percent, due to a main turbine trip on March 22, 2008. The main turbine trip was caused by an invalid main turbine/generator overspeed protection signal (power/load unbalance). The invalid signal was later determined to have originated from a faulty relay in the main generator protection system. On March 24, 2008, operators commenced a reactor startup. Full RTP was achieved on March 25, 2008.

Unit 1 remained at full RTP for the remainder of the inspection period.

Unit 2 began the inspection period operating at full RTP. On February 1, 2008, Unit 2 automatically scrammed due to a main turbine trip following a main generator lockout. A subsequent investigation determined the main generator lockout was caused by overheating of a connection between the isolated bus flexible link and the low voltage (22 kilovolt) bushing at the 2A main transformer. Following repairs and an extent-of-condition review, operators commenced a reactor startup on February 7, 2008. On February 10, 2008, with Unit 2 operating at 81 percent power, operators reduced power and secured the 2A reactor recirculation pump (RRP) due to high unidentified dryweilleakage. Following maintenance on the 2A RRP and repairs to the RRP drain lines, operators commenced a reactor startup on February 12, 2008. Full RTP was achieved on February 15, 2008. Unit 2 remained at full RTP for the remainder of the inspection period.

1. REACTOR SAFETY Cornerstones: Initiating Events, Mitigating Systems. and Barrier Integrity 1R01 Adverse Weather Protection (71111.01-1 sample)

a. Inspection Scope The inspectors evaluated Exelon's preparations and protection for cold weather. On February 5, 2008, the inspectors walked down the Unit 2 Condensate Storage Tank (CST), Unit 1 Circulating Water System, Unit 1 and Unit 2 Isophase Cooling System, and Unit 1 and Unit 2 Main Turbine Lubricating Oil System to verify valve lineups and to observe system operating parameters. The inspectors verified that heat trace systems for Unit 1 and Unit 2 CSTs and the Refueling Water Storage Tank (RWST) were in operation. The inspectors observed plant conditions and evaluated those conditions against criteria documented in procedure GP-7, "Cold Weather Preparation and Operation." The documents reviewed are listed in the Attachment.

b. Findings No findings of Significance were identified.

Enclosure

6 1R04 Equipment Aliqnment (71111.04)

.1 Partial Walkdown (71111.04Q - 3 samples)

a. Inspection Scope The inspectors performed a partial walkdown of the plant systems listed below to verify the operability of redundant or diverse trains and components when safety-related equipment in the opposite train was either inoperable, undergoing surveillance testing, or potentially degraded. The inspectors used plant Technical Specifications (TS), Exelon operating procedures, plant piping and instrumentation drawings (P&IDs), and the Updated Final Safety Analysis Report (USFAR) as guidance for conducting partial system walkdowns. The inspectors reviewed the alignment of system valves and electrical breakers to ensure proper in-service or standby configurations as described in plant procedures and drawings. During the walkdown, the inspectors evaluated material condition and general housekeeping of the system and adjacent spaces. The*

documents reviewed are listed in the Attachment. The inspectors performed walkdowns of the following areas:

• Unit 1 and Unit 2 residual heat removal (RHR) systems after discovery of a pinhole water leak on the 2A RHR heat exchanger supply line;

• Residual Heat Removal Service Water (RHRSW); and

• Unit 1 High Pressure Coolant Injection (HPCI) during maintenance on room coolers.

b. Findings \

No findings of significance were identified .

.2 Complete System Walkdown (71111.04S - 1 sample)

a. I nspection Scope The inspectors conducted one complete system walkdown of the Unit 1 RHR system to verify that equipment was properly aligned. The walkdown included reviews of valve positions, major system components, electrical power availability, and equipment deficiencies. The inspectors reviewed system check off lists, system operating procedures, the system P&IDs and the UFSAR. The i(Jspectors reviewed outstanding maintenance activities and issue reports (IRs) associated with the Unit 1 RHR system to determine if they would adversely <1ffect system operability. The walkdown also included an evaluation of system piping, supports, and component foundations to ensure they were not degraded. The documents reviewed are listed in the Attachment.

b. Findings No findings of significance were identified.

1R05 Fire Protection Fire Protection - Tours (71111.05Q - 5 samples)

a. Inspection Scope Enclosure

7 The inspectors conducted a tour of the five areas listed below to assess the material condition and operational status of fire protection features. The inspectors verified that combustibles and ignitibn sources were controlled in accordance with Exelon's administrative procedures, fire detection and suppression equipment was available for use, and that passive fire barriers were maintained in good material condition. The inspectors also verified that station personnel implemented compensatory measures for out-of-service, degraded, or inoperable fire protection equipment in accordance with the station's fire plan. The documents reviewed are listed in the Attachment. The

'inspectors toured the following areas:

• Unit 1 RHR Heat Exchanger and Pump Rooms;

• Unit 1 '8' and 'D' RHR Heat Exchanger and Pump Rooms;

• D22 Diesel Generator Room and Fuel Oil/Lubricating Oil Tank;

• Unit 2 '8' Core Spray Room; and

• Unit 1 Drywell.

b. Findings No findings of significance were identified.

1R08 In-Service Inspection (71111.08 - 1 sample)

a. Inspection Scope Activities inspected during the Unit 1 refueling outage (1R12) included observations of ultrasonic testing (UT) in progress and analysis of test results using both manual UT techniques and a vendor-based computer UT system. This included the areas of the inner radius of the reactor vessel shell-to-nozzle N178, Zone 2A; the 2" diameter pipe to elbow weld RW118; the dissimilar metal (DM) nozzle to safe end welds DCA-319-1 N5A and DCA-320-1 N58 in the core spray system; and the main steam pipe to isolation valve weld MSA 023R located outside of the containment wall. The inspector also reviewed a sample of in-vessel visual inspection (lWI) video records for jet pump components and the steam dryer. The inspector reviewed test data for several ultrasonic and visually-identified indications and confirmed that Exelon evaluated the data as part of the in-service inspection process.

The inspector reviewed the results of radiographic testing (RT) dated February 8, 2008, for circumferential pipe welds SW1 and SW2 in the Unit 1 reactor core isolation cooling (RCIC) system as performed per the RT procedure 94-RT-011, Revision 6. The inspector reviewed the radiographs and RT documentation for comparison to the American Society of Mechanical Engineers (ASME) Code fabrication requirements. The inspector also noted the sensitivity of the radiographic method as shown by the penetrameter and densitometer measurement, the identification of the radiographer, and acceptance by the RT data reviewers.

Inspection included review of Engineering Change Request (ECR) LG-07-00381-004 for the repair of thinned RHRSW system pipe wall documented in IR 508152. The inspector verified that the repairs, by weld overlay of areas of the '8' RHRSW Return Header, met Regulatory Guide 1.147 and the ASME Code Cases N-513-1 and N-661. The inspector reviewed mock-Up repair procedures and verified the welding procedure and the welder Enclosure

8 qualifications met the requirements of the ASME Code. The inspector observed several of the completed weld overlay repairs to verify compliance with the ASME Code.

The inspector compared Exelon's DM Weld program with the Electric Power Research Institute (EPRI) Boiling Water Reactor Vessel and Internals Project letter 2007-367 (BWRVIP-2007C367), "Recommendations Regarding Dissimilar Metal Weld Examinations,"and BWRVIP-75A, "Technical Basis for Revisions \p NRC Generic Letter (GL) 88-01 Inspection Schedules." The inspector reviewed the data of previous and current (1 R12) automated ultrasonic examination of the safe end to nozzle welds N5A and N5B, DCA-319-1 and DCA-320-1, for the disposition of recordable indications.

While no UT indications from previous outages required re-examination during 1R12, the inspector reviewed the condition of N2H, a safe end to nozzle weld, as determined in the 2004 refuel outage, and the basis for the re-examination scheduled during the 1R13 outage. The inspector walked down portions of the drywell and external portions of the containment boundary with one of the site visual examiners to confirm the acceptance of a sample of the visual examinations made per procedures MAG-CG-425, "Visual Examination of Containment Vessels and Internals", Revision 4, and procedure ER-M-335-018, "Visual Examination of ASME Class MC and CC Containment Surfaces and Components," Revision 5.

The inspectors reviewed the extent of oversight of in-service inspection (lSI) and non-destructive examination activities, including the topics of current lSI oversight and surveillance. The inspector reviewed a sample of IRs to confirm that identified problems were being documented for evaluation and proper resolution. The documents reviewed are listed in the Attachment.

t

b. Findings No findings of significance were identified.

1R11 Licensed Operator Requalification Program - (71111.11- 1 sample)

a. Inspection Scope On January 22, 2008, the inspectors observed the administration of as-found evaluated licensed operator requalification simulator scenarios. The same scenario was administered twice to different crews. The scenario included a simulated reactor pressure instrument failure, a small dryweilleak, a full power anticipated-transient-without-a-scram (ATWS), and a Group 1 containment isolation. The inspectors observed the performance of both operating crews responding to the simulator scenarios. The inspectors assessed licensed operator performance, including operating critical tasks that measure operator actions required to ensure the safe operation of the reactor and protection of the nuclear fuel and primary containment barriers. The inspectors observed the training evaluators' critiques at the conclusion of each scenario.

The documents reviewed are listed in the Attachment.

b. Findings No findings of Significance were identified.

Enclosure

9 1R12 Maintenance Effectiveness (71111.12 -1 sample)

a. Inspection Scope The inspectors evaluated Exelon's work practices and follow-up corrective actions for structures, systems, and components (SSCs) and identified issues to assess the effectiveness of Exelon's maintenance activities. The inspectors reviewed the performance history of risk significant SSCs and assessed Exelon's extent-of-condition determinations for those issues with potential common cause or generic implications to evaluate the adequacy of the station's corrective actions. The inspectors assessed Exelon's problem identification and resolution actions for these issues to evaluate whether Exelon had appropriately monitored, evaluated, and dispositioned the issues in accordance with Exelon procedures'and the requirements of 10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance." In addition, the inspectors reviewed selected SSC classifications, performance criteria and goals, and Exelon's corrective actions that were taken or planned, to evaluate whether the actions were reasonable and appropriate. The documents reviewed are listed in the Attachment. The inspectors performed the following sample:

• 2A-X101 Transformer Low Voltage Bushing to Flexible Link Connection Failure, IR 730021

b. Findings

Introduction:

The inspectors identified a Green, self-revealing finding for an inadequate maintenance procedure regarding electrical connections associated with the Unit 2A Main Transformer.

Description:

On February 1, 2008, with Unit 2 at 100 percent power, Unit 2 automatically scrammed due to an automatic main turbine trip following a generator lockout. The cause of the generator lockout was an isolated-phase bus ground fault on the 2A Main Transformer. The ground fault was caused by overheating of the phase connection between the isolated-phase bus flexible link and the low voltage bushing.

The 2A Main Transformer bushings were replaced in March 2007 when the transformer was exchanged with a spare. Investigation revealed that the cause of the overheated flexible link was due to an inadequate maintenance procedure. A similar event had occurred in May 2000 when Unit 1 automatically scrammed due to a main transformer phase-to-phase fault. Prior to 2001, transformer maintenance was performed by Exelon Energy Delivery (EED). As a result of the 2000 automatic scram, maintenance procedure M-035-003, "X101 Oil Cooled Transformers Cleaning, Examination, and Testing" was created for EED as a guide to properly assemble bolted connections. The procedure combined EED drawings and previous maintenance procedures to create a station specific procedure. In 2001, maintenance ownership of the transformers was transferred to the Limerick Generating Station. Following the transition of transformer maintenance responsibility, the maintenance procedure was revised such that technical information pertaining to the use of anti-oxidant grease, surface preparation, and bolt torque requirements had been moved, omitted, or lost clarity in the procedure. Exelon determined that the procedure was not clear on how to properly prepare an aluminum bushing terminal and had omitted the use of anti-oxidant grease on the connection to Enclosure

10 protect the aluminum bushing flange from oxidation. Also, the procedure did not specify torque requirements for bolted connections with Belleville washers.

The performance deficiency associated with this event was an inadequate maintenance procedure for performing electrical connections on the Unit 2A Main Transformer bushings. The procedure used was insufficient to ensure proper connection of the bushings. The procedure was not clear as to the appropriate method to prepare the surface for an aluminum bushing terminal and did not provide adequate information on

• torque requirements and the use of anti-oxidant grease. This resulted in a Unit 2 reactor scram on February 1, 2008. Exelon entered this issue into the corrective action program as IR 730021. Exelon performed repairs and revised the procedure to reflect the appropriate information to successfully assemble the connection.

Analysis: The issue is more that minor because it is associated with the procedure quality attribute of the Initiating Events comerstone and affected the objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. The inspectors evaluated the finding using Phase 1 of IMC 0609, Appendix A, "Significance Determination of Reactor Inspection Findings for At-Power Situations." This finding was determined to be of very low safety significance (Green) because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation eqUipment or functions would be unavailable.

This finding does not have a cross-cutting aspect because it is not reflective of current station performance. The procedure used to perform the maintenance was created in January 2001.

I Enforcement: Enforcement action does not apply because the performance deficiency did not involve a violation of regulatory requirements. Specifically, the performance deficiency involved the 2A main transformer, a non-safety related component. However, failure of the 2A main transformer due to an inad~quate maintenance procedure was considered a finding and was entered in to the CAP as IR 730021. (FIN 05000353/2008002-01, Inadequate Maintenance Procedure for the 2A Main Transformer) 1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13 - 5 samples)

a. Inspection Scope The inspectors evaluated the effectiveness of Exelon's maintenance risk assessments required by 10 CFR 50.65(a)(4). This inspection included discussion with control room operators and risk analysis personnel regarding the use of Exelon's on-line risk monitoring software. The inspectors reviewed equipment tracking documentation, daily work schedules, and performed plant tours to gain assurance that the actual plant configuration matched the assessed configuration. Additionally, the inspectors verified that Exelon's risk management actions, for both planned and emergent work, were consistent with those described in Exelon procedure, ER-AA-600-1042, "On-Line Risk Management." The documents reviewed are listed in the Attachment. Inspectors reviewed the following samples:

• Unit 2 RHRSW Leak on the Unit 2 RHR Exchanger Supply, IR 716872;

• D23 Diesel Generator Overvoltage, IR 721408; Enclosure

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• Emergent Maintenance on 'B' Control Room Emergency Fresh Air Supply (CREFAS) with the 'A' Standby Gas Treatment (SBGT) System Out-of-Service for Planned Maintenance, IR 725441;

• 023 Emergency Diesel Generator (EDG) Jacket Water Cooling Pump Contactor Replacement, IR 737389; and

• 'B' RHRSW Return Header Repair Due to Pipe Wall Thinning, IR 737033.

b. Findings No findings of significance were identified.

1R 15 Operability Evaluations (71111.15 - 5 samples)

a. Inspection Scope For the five operability evaluations described below, the inspectors assessed the technical adequacy of the evaluations to ensure that Exelon properly justified TS operability and verified that the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors reviewed the UFSAR to verify that the system or component remained available to perform its intended safety function. In addition, the inspectors reviewed compensatory measures implemented to ensure that the measures worked and were adequately controlled. The inspectors also reviewed a sample of issue reports to verify that Exelon identified and corrected deficiencies associated with operability evaluations. The documents reviewed are listed in the Attachment. The inspectors performed the following assessments:

• 1A RHR Unit Cooler Flowrate Difference, IR 681355;

• Division 1 Redundant Reactivity Control System (RRCS) Alarms Received in the Main Control Room, IR 718479;

• 014 Diesel Generator Lubricating Oil Flashpoint Decline, IR 736831;

• Unit 1 HPCI Oil Filter Clogging due to Corrosion Products, IR 744446; and

• Unit 1 Main Turbine Bypass Valve Number 4 Operation Following Turbine Trip and Reactor Scram, IR 753365.

b. Findings Introduction. The inspectors identified a Green finding for failure to identify corrective actions for unsatisfactory performance of a main turbine bypass valve following the March 22, 2008, Unit 1 scram.

Description. During the performance of GP-18, "Scram/ATWS Event Review," following the Unit 1 turbine trip and reactor scram on March 22, 2008, Exelon identified unsatisfactory performance of the main turbine bypass system. Specifically, the number four bypass valve opened sequentially out-of-order (i.e., after bypass valves number five and number six) following the main turbine trip. Engineering personnel identified this adverse condition while performing GP-18, Attachment 8, "Engineering Event Investigation." Per procedure, Exelon entered the issue in the CAP as IR 753365.

The inspectors reviewed IR 753365 and identified that the Station Oversight Committee closed this IR to IR 753306. Further review of IR 753306, which was written to address the cause of the scram, showed that Exelon did not address the adverse condition Enclosure

12 associated with the number four bypass valve opening sequentially out-of-order. The inspectors questioned the appropriateness of not evaluating the number 4 bypass valve condition prior to plant restart which occurred on March 24, 2008. The inspectors also noted that the condition was not reviewed during the Plant Operations Review Committee plant restart meeting which occurred on March 23, 2008, as expected.

Exelon entered this issue into the CAP as IR 754571. On March 26, 2008, Operations declared the number four bypass valve inoperable per TS 3.7.8, "Main Turbine Bypass System," due to its demonstrated performance following the main turbine trip on March 22,2008.

The performance defiCiency associated with this event is the failure to identify corrective actions for unsatisfactory performance of the Unit 1 number four main turbine bypass valve following an automatic scram event on March 22, 2008, as identified in IR 753365.

Analysis. The finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspector assessed the finding using Phase 1 of IMC 0609, Appendix A, "Significance Determination Process for Reactor Inspection Findings for At-Power Situations" and determined the finding to be of very low safety significance (Green) because the finding did not represent an actual loss of safety function of a Single train for greater than its TS allowed outage time.

This finding has a cross-cutting aspect of Problem Identification and Resolution because Exelon did not thoroughly evaluate the problem such that the resolution addressed the

\ cause and did not evaluate the effect the adverse condition had on system operability (P.1 (cl). This finding is discussed in Exelon's CAP as IR 754571.

Enforcement. Enforcement action does not apply because the performance deficiency did not involve a violation of regulatory requirements. Specifically, the performance deficiency involved the main turbine bypass valve system which is not safety-related.

However, failure to correct the unsatisfactory performance of the number four turbine bypass valve following the March 22, 2008, Unit 1 scram was considered a finding. This issue was entered in to the CAP as IR 754571. (FIN 0500035212008002-02, Failure to Correct Main Turbine Bypass Valve Adverse Condition.)

1R 18 Plant Modifications (71111.18 - 1 sample)

Temporarv Modifications

a. Inspection Scope The inspectors reviewed the plant modification listed below to ensure that installation of the modification did not adversely affect systems important to safety. The inspectors compared the modification with the UFSAR and TS to verify that the modification did not affect system operability or availability. The inspectors ensured that station personnel implemented the modification in accordance with the applicable temporary configuration change process. The inspectors also reviewed the impact on existing procedures to verify Exelon made appropriate revisions to reflect the temporary configuration change.

The documents reviewed are listed in the Attachment. The inspectors reviewed the following:

• LG 08-00055, "2A Recirculation Drain Line Modification."

Enclosure

13

b. Findings No findings of significance were identified.

1R19 Post-Maintenance Testing (71111.19 - 6 samples)

a. Inspection Scope The inspectors reviewed the six post-maintenance tests (PMTs) listed below to verify that procedures and test activities ensured system operability and functional capability.

The inspectors reviewed Exelon's test procedures to verify that the procedures adequately tested the safety functions that may have been affected by the maintenance activity, and that the acceptance criteria in the procedures were consistent with information in the licensing and design basis documents. The inspectors also witnessed the test or reviewed test data to verify that the results adequately demonstrated restoration of the affected safety functions. The documents reviewed are listed in the Attachment. The inspectors performed the following samples:

• 023 EOG governor tuning response time test following planned system maintenance;

• 2C-V512/2G-V210 vent fan relay repairs;

• Source range monitor (SRM) functional test following repair to the 'A' SRM;

• ST-4-LLR-051-1 following repairs to MSIV 1F028C due to failed local leak rate testing;

• Unit 1 main generator protection relay replacements; and

• Post maintenance testing following 014 EOG K1 relay repairs.

b. Findings No findings of significance were identified.

1R20 Refueling and Other Outage Activities (71111.20 - 4 samples)

.1 Unit 2 Automatic Reactor Scram

a. Inspection Scope The inspectors evaluated the activities associated with the forced outage that occurred as a result of a Unit 2 automatic reactor scram (2F40) on February 1, 2008. A phase-to-ground fault on the 2A main transformer actuated the main generator neutral overvoltage relay which tripped the generator protection lockout relays and resulted in a main turbine trip and subsequent automatic reactor scram. The documents reviewed are listed in the Attachment. From February 1 through February 8, 2008, the inspectors monitored the activities listed below:

• Limerick's forced outage plan, including appropriate consideration of risk, industry experience, and previous site-specific problems;

• Plant Operations Review Committee and Outage Control Center meetings;

• 2A main transformer troubleshooting and repair activities;

• Repairs to the 2B RRP seal; Enclosure

14

• Unit 2 drywell initial tour and closeout inspection; and

• Portions of the reactor startup and ascension to fUll-power operation.

b. Findings No findings of significance were identified .

.2 Unit 2 Manual Shutdown Due to High Drywell Leakage

a. Inspection Scope The inspectors reviewed the station's work schedule for the Unit 2 manual shutdown and forced outage (2F41) due to high dryweilleakage which was conducted February 10 through February 13, 2008. The inspectors reviewed Exelon's development and implementation of outage plans and schedules to verify that risk, industry experience, previous site-specific problems, and defense-in-depth were considered. During the outage, the inspectors observed the transfer of Unit 2 to single recirculation loop operations, portions of the shutdown and cooldown processes, and monitored Exelon's controls associated with the following outage activities:

• Configuration management, including maintenance of defense-in-depth, commensurate with the forced outage plan for key safety functions and compliance with the applicable TS when taking equipment out of service;

• Implementation of clearance activities and confirmation that tags were properly hung and that equipment was a~propriately configured to safely support the associated work or testing;

• Monitoring of decay heat removal operations;

• Unit 2 drywell initial inspection; and

• Portions of reactor startup and ascension to full-power operation.

b. Findings No findings of significance were identified

.3 Unit 1 Maintenance and Refueling Outage

a. Inspection Scope The inspectors reviewed the station's work schedule and outage risk plan for the Limerick Unit 1 maintenance and refueling outage (1 R12), which was conducted March 1 through March 20, 2008. The inspectors reviewed Exelon's development and implementation of outage plans and schedules to verify that risk, industry experience, previous site-specific problems, and defense-in-depth were considered. During the outage, the inspectors observed portions of the shutdown and cooldown processes and monitored Exelon controls associated with the following outage activities:

• Configuration management, including maintenance of defense-in-depth, commensurate with the outage plan for the key safety functions and compliance with the applicable TS when taking equipment out of service; Enclosure

15

• Implementation of clearance activities and confirmation that tags were properly hung and that equipment was appropriately configured to safely support the associated work or testing;

• Installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication and instrument error accounting;

• Status and configuration of electrical systems and switchyard activities to ensure that TS were met;

• Monitoring of decay heat removal operations;

• Impact of outage work on the ability of the operators to operate the spent fuel pool cooling system;

• Reactor water inventory controls, including flow paths, configurations, alternative means for inventory additions, and controls to prevent inventory loss;

• Activities that could affect reactivity;

• Maintenance of secondary containment as required by TS;

• Refueling activities, including fuel handling and fuel receipt inspections;

• Startup and ascension to full power operation, tracking of startup prerequisites, and walkdown of the drywell (primary containment) to verify that debris had not been left which could block emergency core cooling system suction strainers; and

• Identification and resolution of problems related to refueling outage activities.

b. Findings

Introduction:

The inspectors identified a Green, non-cited violation of TS 6.8.1, "Procedures and Programs," in that Limerick did not implement prompt actions to recover level in the skimmer surge tank (SST) which resulted in elevated radiation levels on the refueling floor and entrainment of air in the Unit 1B RHR pump.

Description:

At 10:55 p.m. on March 9, 2008, with Unit 1 shutdown in a refueling outage, the refueling bridge area radiation monitor alarmed and personnel on the refueling floor noticed several air bubbles in the reactor cavity. Operations personnel entered off-normal procedure ON-120, "Fuel Handling Problems," and evacuated the refuel floor. At 11: 15 p.m., operators secured the 1B RHR pump to terminate air entrainment and established condensate transfer make-up to the reactor cavity through the 1D low pressure coolant injection system (LPCI) in order to recover level in the SST.

During this event, the 1B RHR pump was operating in the alternate decay heat removal (ADHR) line-up. ADHR is a method of decay heat removal in which the RHR pump draws water from the SST, which is connected to the reactor cavity via a weir gate, then discharges the water through the RHR heat exchanger and back to the reactor cavity.

Operators normally maintain sufficient water level in the SST by controlling the amount of water added to and discharged from the reactor cavity. During ADHR operation, water level in the SST is typically maintained at greater than 20 feet.

At approximately 6:30 p.m., water level in the SST lowered to less than 20 feet and continued to slowly lower until operators secured the 1B RHR pump at 11:15 p.m.

Though the operators logged the "Fuel Pool Cooling and Clean-up System Trouble Alarm" at 10:50 p.m., the inspectors determined, based on plots of SST level over time, that the alarm actually should have annunciated at approximately 9:45 p.m. Further discussions with Exelon operations personnel confirmed that operators did receive the alarm at around 9:45 p.m., but believed that it was caused by activities associated with Enclosure

16 the ongoing D11 EDG surveillance testing. As a result, the operators did not immediately inform the control room supervisor and did not promptly implement the actions required per the alarm response card (ARC). The inspectors noted that procedure OP-AA-103-102, 'Watchstanding Practices," directs operators to aggressively investigate alarms to fully understand the reason for the alarm and review and perform the ARC for all unexpected alarms. At around 10:20 p.m., the main control room operators dispatched an equipment operator to the local panel to verify SST level and at 10:29 p.m., the operators reduced cavity discharge flowrate by 10 gallons per minute.

The performance deficiency associated with this event is failure to promptly implement actions described in the ARCs to recover level in the SST. ARC-MCR-112 J5, "Fuel Pool Cooling and Clean-up System Trouble," directs the main control room operators to dispatch an operator to the local alarm panel and implement actions required by the respective local panel ARC. ARC-BOP-10C222 B4, "Skimmer Surge Tank Low Level,"

instructs operators to restore water level in the SST. Operator response to the lowering SST level and "Fuel Pool Cooling and Clean-up System Trouble" alarm was considered untimely in two respects. First, lowering SST trends were available for monitoring and operator action for a period of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and 25 minutes before the air entrainment event.

Secondly, one hour and 10 minutes passed between receipt of the control room alarm and 10:55 p.m., sufficient time for the operators to have responded to the condition and prevented the event.

Analysis: The finding is more than minor because it affects the human performance attribute of the Initiating Events cornerstone and the objective of limiting the likelihood of those events that upset plant stability and challenge critical safetl( functions during shutdown as well as power operations. Prompt action by the ope'rators would have prevented entrainment of air into the RHR system, elevated radiation levels on the refuel floor, and subsequent entry into procedure ON-120, "Fuel Handling Problems." The inspectors evaluated this finding using Attachment 1 of IMC 0609, Appendix G, "Shutdown Operations Significance Determination Process." This finding is of very low safety significance because the finding did not represent a loss of control and did not require quantitative assessment per Checklist 7 of Attachment 1 to IMC 0609, Appendix G. Specifically, the reactor time-to-boil during this event was approximately 26 hours3.009259e-4 days <br />0.00722 hours <br />4.298942e-5 weeks <br />9.893e-6 months <br />, time to core uncover was greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and adequate time was available to vent and restart the affected RHR pump in the ADHR mode of operation. Additionally, during the time that ADHR was secured, natural circulation provided reactor coolant flow.

This issue has a human performance cross-cutting aspect in the area of work practices.

Operators did not follow OP-AA-103-102, 'Walchstanding Practices," and thus did not promptly implement actions required by the applicable alarm response procedure to recover SST level (H.4(b)).

Enforcement: Technical Specification 6.8.1, "Procedures and Programs," states, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures as recommended in NRC Regulatory Guide 1.33, "Quality Assurance Program ReqUirements (Operation)," Appendix A, February 1978.

Regulatory Guide 1.33, Appendix A, Section 5.0, requires procedures for abnormal, off-normal, or alarm conditions. ARC-BOP-10C2222 B4, "Skimmer Surge Tank Low Level,"

instructed the operators to restore level in the SST. Contrary to this requirement, on March 9, 2008, operators did not promptly implement actions to recover level in the SST Enclosure

17 for one hour and 10 minutes following receipt of the associated control room alarm. The delay in implementation of actions resulted in elevated radiation levels on the refuel floor and entrainment of air in the 1B RHR system which had the potential to cause a loss of ADHR. Because this finding is of very low safety significance and Exelon has entered this issue into their corrective action program (IR 747235), this violation is being treated as a non-cited violation consistent with Section VI.A of the NRC Enforcement Policy.

(NCV 05000352/2008002-03, Failure to Promptly Implement Actions for a Low SST Level)

.4 Unit 1 Automatic Reactor Scram

a. Inspection Scope The inspectors evaluated the activities associated with the forced outage that occurred as a result of a Unit 1 automatic reactor scram (1 F43) on March 22, 2008. An invalid main turbine/generator overspeed protection signal (power/load unbalance) actuated which resulted in a main turbine trip and subsequent reactor scram. The invalid Signal was later determined to be caused by a faulty relay in the main generator protection system. The documents reviewed are listed in the Attachment. From March 22 through March 25, 2008, the inspectors monitored the following activities:

• Limerick's forced outage plan, including consideration of risk, industry experience, and previous site-specific problems;

• Plant Operations Review Committee and Outage Control Center meetings;

• Electrohydraulic control (EHC) system troubleshooting; and

• Portions of the reactor startup and ascension to full-power operation.

b. Findings No findings of significance identified.

1R22 Surveillance Testing (71111.22 - 5 samples)

a. Inspection Scope The inspectors witnessed the performance and reviewed test data for five surveillance tests (STs) that are associated with risk-significant SSCs. The review verified that Exelon personnel followed TS requirements and that acceptance criteria were appropriate. The inspectors also verified that the station established proper test conditions, as specified in the procedures, that no equipment preconditioning activities occurred, and that acceptance criteria had been met. The documents reviewed are listed in the Attachment. The inspectors reviewed STs for the following systems and components:

• ST 092-322-2, D22 Diesel Generator Loss of Coolant Accident/Load Reject Testing and Fast Start Operability Test Run;

• ST-4-051-311-2, 'A' RHR Auto Close S/I Contact;

• ST-6-051-231-2, 'A' RHR Pump, Valve, and Flow Test;

• ST-6-107-640-1, Reactor Vessel Temperature and Pressure Monitoring; and

• ST-4-LLR-051-1, Main Steam Line 'C' Local Leak Rate Testing.

EnClosure

18

b. Findings No findings of significance were identified.

2. RADIATION SAFETY Cornerstone: Occupational Radiation Safety 20S1 Access Control to Radiologically Significant Areas (71121.01 - 22 samples)

a. Inspection Scope During the periods of January 7 - 11, 2008, and March 10 -14, 2008, the inspector conducted the following activities to verify that Exelon implemented physical, administrative, and engineering controls for access to locked high radiation areas (LHRAs) and other radiologically controlled areas (RCAs), and that workers were adhering to these controls when working in these areas during power operations and during the Unit 1 refueling outage (1R12). The inspector reviewed implementation of these controls against the criteria contained in 10 CFR 20, TSs, applicable industry standards, and Exelon procedures. This inspection activity represents completion of 22 samples relative to this inspection area. The documents reviewed are listed in the Attachment.

Plant Walkdown and RWP Reviews 1

• The inspector identified exposure significant work areas in Units 1 and 2, including the refuel floor and areas of the Reactor Buildings, Control Structure, Radwaste Building, and Turbine Buildings. The inspector reviewed survey maps and radiation work permits (RWP) for these areas to determine if associated controls were acceptable.

• During the 1R 12 refueling outage, the inspector identified exposure significant work areas in the Unit 1 drywell, refuel floor, and reactor building. Specific work activities included: replacement of the RHR 50B valve, phase II fuel shuffle, in-vessel visual inspection (lWI), and Emergency Service Water (ESW) pipe replacement. The inspector reviewed radiation survey maps and RWP associated with these areas to determine if the associated controls were acceptable. RWPs reviewed included; LG-0-08-00092/93, "Remove/Replace 50B Valve:" LG-0-08-00060/69, "Fuel Floor Outage Middle Activities;" and LG-0-08-0013, "ESW Header Pipe Replacement."

• The inspector toured accessible RCAs in the reactor building, radwaste building, and turbine building, for both units. Additionally, the inspector toured the Unit 1 drywell and refueling floor during the March refueling outage. While accompanied by a radiation protection technician, the inspectors performed independent radiation surveys of selected areas to confirm the accuracy of survey maps and the adequacy of postings.

• In evaluating RWPs, the inspector reviewed electronic dosimeter dose/dose rate alarm setpoints to determine if the setpoints were consistent with the survey indications and plant policy. Work activities reviewed in January included installation of scaffolding and temporary shielding in the Unit 1 'A' and 'B' RHR pump rooms to Enclosure

19 support ESW modifications, and dec.ontaminating a reactor cavity work platform.

Work activities reviewed during the Unit 1 outage included removal/replacement of the 50B valve (RWP LG-0-OB-00092), installation/removal of drywell scaffolding (RWP LG-0-OB-000B1), and Refuel Floor Outage Middle Activities (RWP LG-O-OB-00060).

• The inspector examined the airborne monitoring instrurnentation and engineering controls for potential airborne radioactivity areas. The inspector performed plant tours to confirm that the airborne sampling equiprnent was operating and calibrated.

• The inspector reviewed RWPs and associated instrumentation and engineering controls for potential airborne radioactivity areas located in the Unit 1 drywell, reactor bUilding, and refuel floor. The inspector reviewed dose assessment records related to evaluating airborne radioactivity concentrations and personnel contarninations to confirm that no worker received an internal dose in excess of 10 mrern when performing outage related tasks. The inspector reviewed the dose assessment rnethodology for internal exposures that were less than 10 mrem to confirm the accuracy of the results.

• The inspector determined that during 2007, there were no internal exposures that exceeded 50 rnrem Cornmitted Effective Dose Equivalent (CEDE). The inspector also reviewed data for the ten highest exposed individuals for 2007 and the dose/dose rate alarm reports, and determined that no exposure exceeded site administrative, regulatory, or performance indicator criteria. Additionally, the inspector reviewed the dosimetry records and associated documentation for declared pregnant workers to determine if dose was controlled in accordance with 10 CFR 20.120B.

Problem Identification and Resolution

• In January 200B, the inspector reviewed elements of the Exelon's CAP related to controlling access to RCAs, completed since the last inspection of this area, to determine if problems were being entered into the program for resolution. The inspector reviewed 17 IRs, recent station ALARA committee meeting minutes, Common Cause Analysis Reports, a Nuclear Oversight Audit, and Nuclear Oversight Objective Evidence (field observation) Reports for 2007 relating to controlling activities in RCAs to evaluate Exelon's threshold for identifying, evaluating, and resolving occupational radiation safety problems. The review included a check of possible repetitive issues such as radiation worker and radiation protection technician errors.

• Between January 1, 200B and March 14, 200B, the inspector reviewed 27 IRs associated with radiation protection control access. The inspector discussed these IRs with Exelon staff to determine if the follow up activities were being conducted in an effective and timely manner, commensurate with their safety significance.

• The inspector reviewed Exelon's actions taken in response to identifying elevated dose rates on the refueling bridge as identified in IR 747235 (see Section 1R20.3 of this report for further details). As part of this review, the inspector confirmed that workers evacuated the area in response to an area monitor alarm, air samples were taken and evaluated, contamination surveys were performed, and an action plan was Enclosure

20 developed to reduce source term concentrations in the reactor cavity. Additionally, the inspector attended an inter-departmental meeting in the Outage Control Center where source mitigation strategies and dose control measures were developed.

Jobs-In-Progress Review

• The inspector observed aspects of various maintenance activities being performed during the inspection period to verify that radiological controls, such as required surveys, area postings, job coverage, locked high radiation area controls, and pre-job high radiation area (HRA) briefings were conducted. The inspector observed activities to confirm that personnel dosimetry was properly worn, and workers were knowledgeable of work area radiological conditions. Tasks observed included scaffolding/temporary shielding installation in the Unit 1 'A' and '8' RHR pump rooms, and decontaminating a reactor cavity work platform. The inspector attended the pre-job briefings for these jobs to assess the adequacy of information presented and the interdepartmental coordination required in completing these tasks.

High Risk Significant, High Dose Rate HRA, and Very High Radiation Area Controls

• The inspector discussed high dose rate (HDR) areas and Very High Radiation Area (VHRA) areas controls and procedures with a radiation protection supervisor. The inspector reviewed Exelon procedures to verify that procedure changes did not substantially reduce the effectiveness and level of worker protection.

1

• In January 2008, the inspector inventoried keys to Unit 1 and Unit 2 locked high radiation areas (LHRAs) and VHRAs, maintained by the radiation protection department and operations department. During plant tours, the inspector inspected 98 TS LHRAs to ensure they were properly secured and posted. Additionally, during the Unit 1 refueling outage, the inspector inspected accessible LHRAs in the Unit 1 drywell to ensure they were properly secured and posted.

• The inspector reviewed procedures for controlling access to HRAs and VHRAs to determine if the administrative and physical controls were adequate. The inspector also reviewed the physical and procedural controls for securing and removing highly contaminated/activated materials stored in the spent fuel pool. The inspector discussed the adequacy of current access controls with Radiation Protection Management, including prerequisite communications and authorizations, to verify that procedure changes did not substantially reduce the effectiveness and level of worker protection.

Radiation Worker/Radiation Protection Technician Performance

• The inspector assessed radiation worker and radiation protection technician performance by attending pre-job briefings for various jobs-in-progress, attending morning departmental meetings, and observing in-plant/control point activities.

Through interviews and task observations, the inspector evaluated job preparations, the degree of technician coverage for work performed in the HRAs, and the knowledge level of the workers for specific tasks.

Enclosure

21

.* The inspector observed and questioned radiation workers and radiation protection technicians while conducting various outage tasks, including removal/replacement of the RHR 50B valve, various refuel floor activities, and drywell radiography tasks.

• The inspector reviewed IRs related to radiation worker and radiation protection technician errors, and personnel contamination event reports to determine if an observable pattern traceable to a similar cause was evident.

b. Findings No findings of significance were identified .

.2 ALARA Planning and Controls (71121.02 - 9 samples)

a. Inspection Scope During the period March 10 -14, 2008, the inspector conducted the following activities to verify that Exelon implemented operational, engineering, and administrative controls to maintain personnel exposure as-Iow-as-is-reasonably-achievable (ALARA) for tasks conducted during the Unit 1 refueling outage (1R12). Implementation of these controls was reviewed against the criteria contained in 10 CFR 20, applicable industry standards, and Exelon procedures. This inspection represents completion of nine samples relative to this inspection area. The documents reviewed are listed in the Attachment.

Radiological Work Planning

• The inspector reviewed information regarding outage exposure history, current exposure trends, and ongoing activities to assess current performance and outage exposure challenges. The inspector determined the site's three-year rolling collective average exposure.

• The inspector reviewed the 1R12 outage work scheduled during the outage period and the assqciated work activity dose estimates and ALARA Plans (AP). Scheduled work included the removal/replacement of the RHR 50B valve (AP 2008-024), the ESW header pipe replacement (AP 2008-005), snubber inspections (AP2008-019),

DW shielding installation (AP2008-026), DW scaffolding removal (AP 2008-09),

control rod drive exchange (AP2008-003), in-core instrument change-out (AP 2008-016), and various activities on the reactor cavity work platform (RCWP) (AP 2008-030).

• The inspector evaluated the departmental interfaces between radiation protection, operations, maintenance crafts, and engineering to identify missing ALARA program elements and interface problems. The inspector accomplished the evaluation by attending a daily work scheduling/status meeting in the Outage Control Center and a Station ALARA Committee meeting, reviewing recent Station ALARA Council meeting minutes, work-in-progress ALARA reviews, and Nuclear OverSight Objective Evidence Reports, and intervieWing the site Radiation Protection Manager.

• The inspector also reviewed the status of long term projects, designed to reduce personnel exposure, as contained in 2006-2011, "Exposure Reduction Plan."

Enclosure

22 Verification of Dose Estimates

• The inspector reviewed the assumptions and basis for the annual (2008) site collective exposure projections for the 1R 12 outage and for routine power operations.

• The inspector reviewed Exelon's procedures associated with monitoring and re-evaluating dose estimates when the forecasted cumulative exposure for tasks differed from the actual exposure received. The inspector reviewed the dose/dose rate alarm reports, work-in-progress evaluations, and exposure data for selected individuals receiving the highest Total Effective Dose Equivalent (TEDE) for 2008 to confirm that no individual exposure exceeded the regulatory limit, or met the performance indicator reporting guideline. Included in this review were the actions taken to control dose on the RCWP, following the identification of elevated cavity dose rates.

Jobs-I n-Progress

• The inspector observed various 1R12 jobs-in-progress to evaluate the effectiveness of dose control measures. Jobs observed included removal/replacement of the RHR 50B valve, DW scaffolding disassembly, the 50B radiography, RCWP activities, fuel shuffle, and ESW piping replacement. As part of this evaluation, the inspector reviewed the RWP, survey maps, shielding effectiveness, and contamination control measures. The inspector attended the pre-job briefing for radiographic examinations to be performed on the newly installed RH R 50B valve to determine if affected areas were properly controlled\

Source Term Reduction and Control

• The inspector reviewed the status and historical trends for the Unit 1 source term.

By reviewing survey maps and interviewing the Radiation Protection Manager, the inspector evaluated the recent source term measurements and control strategies.

Specific strategies employed by Exelon included performing a reactor soft shutdown, system flushes, installation of permanent and temporary shielding in the drywell, vacuuming the seal plate, hydrolazing of reactor nozzles, and increasing the capacity of the reactor cavity filtration system.

Declared Pregnant Workers

• The inspector reviewed the radiological controls and dosimetry records for one declared pregnant worker to determine if procedural exposure controls were properly implemented.

Problem Identification and Resolution

• The inspector reviewed elements of Exelon's corrective action program related to implementing ALARA program controls, including IRs, Nuclear Oversight Objective.

Evidencereports, and Station ALARA Committee meeting minutes to determine if problems were being entered at a conservative threshold and resolved in a timely manner.

b. Findings No findings of significance were identified.

Enclosure

23

4. OTHER ACTIVITIES 40A1 Performance Indicator (PI) Verification (71151 - 4 samples)

a. Inspection Scope The inspectors sampled Exelon's submittal of the initiating events and mitigating systems perfonnance indicators listed below to verify the accuracy of the data recorded from the fourth quarter of 2007 through the first quarter of 2008. The inspectors utilized performance indicator definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 5, to verify the basis in reporting for each data element. The inspectors reviewed various documents, including portions of the main control room logs, issue reports, power history curves, work orders, and system deviation reports. The inspectors also discussed the method for compiling and reporting performance indicators with cognizant engineering personnel and compared graphical representations from the most recent PI report to the raw data to verify that the report correctly reflected the data. The documents reviewed are listed in the Attachment.

Cornerstone: Initiating Events (2 samples)

• Unit 1 Unplanned Power Changes per 7000 Critical Hours; and

• Unit 2 Unplanned Power Changes per 7000 Critical Hours.

Cornerstone: Mitigating Systems (2 samples)

• Unit 1 Mitigating Systems Performance Index, High Pressure Injection; and

• Unit 2 Mitigating Systems Performance Index, High Pressure Injection.

b. Findings No findings of significance were identified.

40A2 Identification and Resolution of Problems (71152)

Review of Items Entered into the CAP As required by Inspection Procedure 71152, "Identification and Resolution of Problems,"

and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors screened all items entered into Limerick's corrective action program. The inspectors accomplished this by reviewing each new condition report, attending management review committee meetings, and accessing Exelon's computerized database.

40A3 Event Follow-Up (71153)

.1 Plant Event Review

a. Inspection Scope Enclosure

24 and/or observed plant For the three plant events listed below, the inspectors reviewed ance of mitigating parameters, reviewed personnel performance, and evaluated perform riate regional systems. The inspectors communicated the plant events to approp in IMC 0309, "Reactive personnel and compared the event details with criteria contained nal reactive Inspection Decision Basis for Reactors," for consideration of additio

's follow- up actions related to the inspection activities. The inspectors reviewed Exelon imple'1 lented comme nsurate events to assure that appropriate corrective actions were with their safety significance.

by a main generator

• Unit 2 automatic reactor scram due to main turbine trip caused fault on February 1, 2008 (2F40);

entrainment in the

• Refueling floor elevated radiation levels during 1R12 due to air alternate decay heat removal system on March 9, 2008; and by invalid power/load

• Unit 1 automatic reactor scram due to main turbine trip caused unbalance signal on March 22, 2008 (1 F43).

b. Findings No findings of significance were identified .

Automatic Actuation of

.2 (Closed) Licensee Event Report (LER) 050000353/2008-002-0, the Reactor Protection System at Power automatically scrammed On February 1, 2008, with the unit at 100 percent power, Unit 2 pf the generator lockout

. due to main turbine trip following a generator lockout. The cause details of this event are

. was a fault on the 'A' phase of the unit main transformer. The d in a Green finding. The inspectors discussed in section 1R12 of this report and resulte This LER is closed.

did not identify any new findings in review of this LER.

40A6 Meetings, Including Exit Exit Meeting Summary tion results to On April 10, 2008, the resident inspectors presented the inspec staff. The inspec tors confirmed that Mr. C. Mudrick and other members of his proprietary information was not included in the inspec tion report.

ATTACHMENT: SUPPLEMENTAL INFORMATION Enclosure

A-1 SUPPLEMENTAL INFORMATION KEY POINTS OF CONTACT Exelon Generation Company C. Mudrick, Site Vice President E. Callan, Plant Manager D. DiCello, Radiation Protection Manager R. Dickinson, Director Engineering R. Kreider, Manager, Regulatory Assurance J. Berg, System Manager, HPCI S. Bobyock, Manager, Plant Engineering S. Breeding, Manager, Operations Support G. Budock, lSI Program Engineer R. Corbit, NDE Manager M. Crim, Manager, Operations Services K. Fisher, NDE Engineer P. Gardner, Director Operations J. George, System Manager, RHR M. Gift, System Manager, Radiation Monitoring Systems R. Gosby, Radiation Protection Technician, Instrumentation C. Gray, Radiological Engineering Manager R. Harding, Engineer, Regulatory Assurance M. Jesse, Nuclear Oversight Manager M. Karasek, Structural Engineering L. Lail, System Manager, EDG D. Malinowski, Simulator Instructor W. Miller, Vendor, NDE Level III J. Sprucinski, Senior Radiation Protection Technician J. Quinn, NSSS Systems Manager P. Weyhmuller, Manager, Plant Engineering LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened None Closed 050000353/2008-002-2 LER Automatic Actuation of the Reactor Protection System (Section 40A3.2)

Opened and Closed 05000353/2008002-01 FIN Inadequate Maintenance Procedure for the 2A Main Transformer (1R12)

Attachment

A-2 05000352/200S002-02 FIN Failure to Correct Main Turbine Bypass Valve Adverse Condition (Section 1R15) 05000352/200S002-03 NCV Failure to Promptly Implement Actions for a Low SST Level (Section 1R20.3)

Discussed

• None LIST OF DOCUMENTS REVIEWED Section 1 R01: Adverse Weather Protection Procedures GP-7, Cold Weather Preparation and Operation, Revision 34, dated 11/20107 S10.7.C, Service Water Flow Adjustments, Revision 21 S17.0.A, Preparing Raw Water System for Winter Operation, Revision 4 OSOS.S.A (COL-1), Lineup for RWST and Associate Pipe Freeze Protection, Revision 5 SE-14, Snow, Revision 13 SOS.S.4, RWST, #1 and #2 CST Freeze Protection, Revision 10 1SOS.8.A (COL-2), Lineup for #1 CST and Associated Pipe Freeze Protection, Revision 4 2S08.8.A (COL-2), Lineup for #2 CST and Associated Pipe Freeze Protection, Revision 5 Section 1 R04: Eguipment Alignment 1

Procedures S12.1.A, RHR Service Water System Startup, Revision 45 OS12.1.A (COL-1), Alignment for Normal Operation of the Residual Removal Service Water System for - Loop A, Revision 23 OS12.1.A (COL-2), Alignment for Normal Operation of the Residual Removal Service Water System for - Loop B, Revision 17 S55.1.A, Normal HPCI Line-up for Automatic Operation, Revision 31 1S55.1.A (COL), Equipment Alignment for Automatic Operation of the HPCI System, Revision

• 24 Issue Reports and Action Reguests IR 440029, Abnormally Low Reading on CI-051-2R613A IR 445317, Unexpected Alarm IR 453419, Vibration Monitoring on RHR SOC Return Check Valves (F050A & B)

IR 456687, Unit 1 RHR A-Loop Snubber Reduction Not Complete IR 456926, Determine if 51-1 F067A & B is Required to be Fully Opened IR 458097, Gross Fail Causes Div 2 RHR OOS IR 467199, LTA Operability Basis Associated 1B RHR and IR for DP Mod IR 467364, HV-051-1F041C Disc has Closed Indication with Valve Open IR 474757, 1 B RHR HTX S/w Side Hi Conductivity While in Lay-Up .

IR 502477, 1A RHR HTX S/w Side Hi Conductivity While in Lay-Up IR 595423, Valve Leaks By When in Fully Closed Position IR 603530, Snubber DCA-418-H004 Bearings Found Locked IR 647234, Discrepancy Between ST-6-051-231-1 and 1ST Valve Database IR 670329, Difficult to Reset Gross Fail During Testing Attachment

A-3 IR 725338, HBC-091- RHRSW Piping Found Below Minimum Wall IR 719555, HBC-507-01 RHRSW Piping Found Below Minimum Wall IR 562081, Heavy Corrosion on RHRSW Piping IR 454475, B RHRSW Discharge Piping Penetration Leaking 30 DPM IR 508152, Raw Water Pipe Thickness Reading Below T-allowable IR 508469, Raw Water Pipe Thickness to Reach Min Wall in 7 Months IR 562081, Heavy Corrosion on RHRSW Piping IR 709748, HBC-091-01 RHRSW Piping Found Below Minimum Wall IR 716872, RHRSW piping Leak on Inlet to 2A RHRSW Heat Exchanger IR 718336, ST-4-012-951-0 Failed Due to Through Wall Leakage Miscellaneous Limerick Generating Station UFSAR Section 9.2.3 Limerick Generating Station Technical Specifications 3/4.7.1 Limerick Generating Station UFSAR Section 6.3.1.2.1/6.3.2.2.1 Limerick Generating Station Technical Specifications 3/4.5 Section 1R05: Fire Protection Procedures 1FSSG-3053, Fire Area 053 Fire Guide, Revision 0 2F-D-315B, D22 Diesel Generator Room and Fuel Oil/Lube Oil Tank Room Rooms 315B and 316B (EI.217) Fire Area 85 Pre-Fire Plan, Revision 5 F-R-181, Unit 2 Core Spray Pump Room B (EL. 177) Fire Area 58 Pre-Fire-Plan, Revision 4 F-R-400, Unit 1 Drywell Area Room 4000 (EL. 237) Fire Area 30, Revision 6 Section 1ROB: In-Service Inspection Procedures GE UT 209-Version 18. Automated Ultrasonic Examination (UT) of Dissimilar Metal Welds, and Nozzle to Safe End Welds GE UT 311-Version 15. Manual UT of Nozzle Inner Radius, Bore and selected Nozzle to Vessel Regions GE -PDI-UT Rev 4. PDI UT Examination of Austenitic Pipe Welds GPB 1R12 Outage Scope for Containment Boundary Integrity Inspections MAG-CG-425, Visual Examination of Containment Vesselsllnternals, Revision 4 ER-AA-335-018, Visual Examination of ASME Class MC and CC Containment Surfaces and Components, Revision 5 AD-AA-2001, Management and Oversight of Supplemental Workforce, Revision 1 ER-AA-335-025, Oversight of Vendor NDE Activities, Revision 3 ISI-NDE Oversight Plan for Limerick Outage Li-1R12, dated 02/21/2008 ASME Code Case N-661 ASME Code Case N-513-1 ASME Section XI Issue Reports and Action Requests AR 00601367. Additional UT Inspections of ESW / RHRSW Pipe 744286,724146,731845,599425,594156,453799, 746850, 746849, 746822, 746851, 746920, 745946 Miscellaneous ECR LG-07-00381-004, Repair or Replacement of Portions of 30" Diameter RHRSW Pipe Attachment

A-4 WPS 1-1-GM-2, Welding Procedure Specification Record (GMAW), Revision 0 WPS 1-1-GM-PWHT-1, Rev 1. Welding Procedure Specification Record (GMAW) Report, Project 124718, Dissimilar Metal Weld Ultrasonic Examination Review for Limerick Unit 1, dated December 2007.

Report No. 601930, dated 3/10/2004. UT ofVRR-1RD-1A N2H, Safe End to Nozzle.

Report No.1 04250, dated 3/12/2008. UT of Weld MSA 023R

• Report No. 238000, dated 3/12/2008. UT of Weld MSA 024 Report No. 601530, dated 3/1212008. UT of Inner Radius of N17-B, LPCI "D" Loop Report No. 601520, dated 3/12/2008. UT of N17-B Nozzle to Vessel Weld Report No. 114250, dated 3/12/2008. UT of RW-118, 2" Pipe to Elbow Weld, RWCU Limerick Unit 1, RFO 1R12 - In Vessel Visual Inspection (IWI) Component Inspection Listing, dated 3/10/2008.

Visual Indication Notification Report for Jet Pumps 18, 19 and 21 wedge areas.

Drawings Drawing, ESW 1 RHRSW Flaw History, dated 02129/2008 Drawing, N5 nozzle assembly & weld details.

Section 1R11: Licensed Operator Regualification Program Procedures EOP T-101, RPV Control, Revision 20 EOP T-102, Primary Containment Control, Revision 22 EOP T-112, Emergency Blowdown, Revision 12

\ EOP T-117, LevellPower Control, Revision 15 EP-AA-1008, Limerick Generating Station Emergency Action Level Matrix, Revision 8 Miscellaneous LSTS~1043, Limerick Simulator Training Scenario, Revision 1 Section 1 R12: Maintenance Effectiveness Procedures ER-AA-310, Implementation of the Maintenance Rule, Revision 6 ER-LG-310-1010, Maintenance Rule Implementations - Limerick Generating Station, Revision 7 Issue Reports and Action Requests IR 734324, Maintenance Rule a(1) Determination for System 35 PEP 10011179, Scram and Turbine Trip from Fault on Main Transformer Section 1R13: Maintenance Risk Assessments and Emergent Work Control Procedures IC-C-11-02001, Field Testing Alternating Current Generators, Revision 1 OP-AA-1 08-115, Operability Determination, Revision 5 S92.9.N, Routine Inspection of the Diesel Generators, Revision 56 Issue Reports and Action Requests IR 716872, RHRSW Piping Leak on Inlet to 2A RHRSW Heat Exchanger IR 721408, D23 Overvoltage Condition During RT-6-092-503-2 IR 725441, TIIC-078-023B Appears to Have Lost Its Program Attachment

A-6 IR 737389, D23 Jacket Water Temperature Low A0681226, DIG Operability with Low Jacket Coolant Temperature Work Orders C0223634 M1650516 Miscellaneous Paragon Risk Assessment, 01/23/2008 Operator Logs, dated 01/22/2008 - 01/23/2008 Operator Logs, dated 02/19/2008 - 02/20/2008 Section 1R15: Operability Procedures MA-AA-716-230-1001, Oil Analysis Interpretation Guide, Revision 6 Issue Reports and Action Requests IR 620856, Unit 2 Automatic Scram IR 681355, 1A RHR Unit Cooler Flowrate Difference (1A-V210)

IR 708564, Measure 1G-V21 0 unit Cooler Air Outlet Flow IR 718479, Div 1 RRCS Alarms Received in the MCR IR 721876, RRCS PRA Could Not Be Performed as Scheduled A1634034, 1A RHR Unit Cooler Flowrate Difference (1A-V210)

A1644945, Div 1 RRCS Alarms Received in the MCR Work Orders C0223447 C0223980 Miscellaneous Limerick Generating Station UFSAR, Section 7.6.1.8 Limerick Generating Station UFSAR, Section 15.8 Limerick Generating Station UFSAR, Table 9.4-7 Limerick Generating Station UFSAR, Section 9.4.2.2 Operator Logs, dated 01/05/2008 Section 1R18: Plant Modifications Drawings 8031-M-43, Sheet 3, P&ID Reactor Recirculation Pump (Unit 2), Revision 15 8031-M-61, Sheet 4, P&ID Liquid Radwaste Collection (Unit 2), Revision 15 Miscellaneous ECR LG 08-00055, 043-2F052A Leaking Past Seat Section 1R19: Post Maintenance Testing Procedures ARC-BOP-2CC208 A 1, RHR Unit Coolers 2C/2GV21 0 Trouble, Revision 0 IC-11-00443, Operational Adjustment of Source Range Monitors, Revision 6 Attachment

A-6 RT-6-092-503-2, 023 Diesel Generator Governor Tuning Response Time Test, Revision 0, completed 01/11/2008 RT-6-092-503-2, 023 Diesel Generator Governor Tuning Response Time Test, Revision 0, completed 01/12/2008 RT 092-503-2, 023 Diesel Generator Governor Tuning Response Time Test, Revision 0, completed 01/13/2008 .

ST-2-074-630-2, Source Range-Monitor Functional Test SRM A, Revision 12, completed 02/03/2008 ST-4-LLR-051-1, Main Steam Line 'C', Revision 10, completed 03/06/2008 ST-4-LLR-051-1, Main Steam Line 'C', Revision 10, completed 03/10/2008 ST-6-092-780-1, Unit 1 Diesel Generator Simultaneous Startup Test, Revision 3 ST-6-092-933-2, 023 Diesel Generator Governor and Voltage Regulator Post-Maintenance Testing, Revision 0 ST-6-107-201-0, 1ST Valve Stroke for New Baseline, Revision 4, completed 03/15/2008 Issue Reports and Action Requests IR 721130, Newly Installed EGA on D23 Could Not Be Tuned Acceptably IR 721267,023 DIG Output Breaker Failed to Close From MCR Handswitch IR 721387, 023 C Exhaust Fan Trouble IR 721408, 023 Overvoltage Condition during RT-6-092-503-2 IR 721412, 2G-V210 Has No Indication IR 721439, PDI-016-203 Indication Lost IR 721494, Need to Remove Rectifier from 023 Diesel IR 721499, 023 Contingent Volt Reg Control Chassis BD Replacement IR 721529, Mechanical Flag Ass<tciated with 152-11707/CS Broken IR 721604, Defective MOC on D23 Regulator IR 721709, Oil Leak Sight Glass C.S. of Engine IR 721742, Speed Setting Adjustment Made to 023 DIG "2C-G501" IR 722097, Hot Spot Found on Incoming Leads to Breaker iR 728111, PMT Issues Associated with Relay Replacements IR 730796, 20 SRM Spikes During CRD - HV-046-2F003, Adjustments IR 749875, HV-041-1F028C Failed ST-4-LLR-051-1 IR 751491, 0-14 K1 Relay Failed to Remain Latched Closed When Reset IR 753856, Original K1 Relay 114-82369 (PIN A 143F) is Obsolete IR 755243, 011 EDG K1 Contactor is Obsolete, Replace With New Model IR 755244,012 EDG K1 Contactor is Obsolete, Replace With New Model IR 755246,013 EDG K1 Contactor is Obsolete, Replace With New Model IR 755247,014 EDG K1 Contactor is Obsolete, Replace With New Model IR 755249, 021 EDG K1 Contactor is Obsolete, Replace With New Model IR 755250, 022 EDG K1 Contactor is Obsolete, Replace With New Model A1519576, HV-041-1F028C MSIV LLRT Rework Contingency ,

A1645898, A & C RHR Pump Room Unit Cooler G A1645899, 023 DIG End HVAC Exhaust Fan C A1648651, 20 SRM Spikes During CRD - HV-046-2F003 Adjustments A1655554, 0-14 K1 Relay Failed to Remain Latched Closed When Reset Work Orders C0223500 C0223507 C0223508 C0223778 Attachment

C0224457 C0224463 Miscellaneous Complex Troubleshooting Failure Mode Tree, D14 K1 Contactor and FU-1A Failures E-69, Single Line Meter & Relay Diagram, MCC Load Tabulation, Sheet 1, Revision 44 E-471 , Schematic Diagram RCIC, HPCI, RHR and Core Spray Room Unit Coolers -1 & 2 Units, Revision 14 E-490, Schematic Diagram Diesel Generator Ventilation Air Exhaust Fans & Aux Control 1 & 2 Units, Sheets 1 and 2, Revision 15 E-686, Schematic Diagram HVAC Miscellaneous Safeguard Instrumentation 1 & 2 Units &

Common, Sheet 6, Revision 12 Limerick Generating Station Rev 0 Schedule, Work Week 0802 Limerick Generating Station UFSAR, Section 9.5.6 8031-M-71-65, Control Schematic D14 Diesel Generator, Sheet 18, Revision 2 8031-M-76, P&ID Reactor Enclosure and Refueling Area - HVAC (Unit 2), Sheet 7 & 8, Revision 12 8031-M-81, P&ID Miscellaneous Structures - HVAC (Unit 2 and Common), Sheet 3, Revision 15 Operator Logs, dated 01/11/2008 through 01/14/2008 Operator Logs, dated 0210112008 through 02/07/2008 Operator Logs, dated 03/26/2008 Technical Specification 3.3.7.6 Technical Specification 3.6.1.2 Section 1 R20: Refueling Outage Activities Procedures ARC-BOP-10C222 B4, 1BT208 Skimmer Surge Tank Low Level, Revision 0 ARC-MCR-112 J5, Fuel Pool Cooling and Clean-up System Trouble, Revision 0 FH-105, Core Component Movement - Core Transfers, Revision 42 GP-2, Normal Plant Start-Up, Revision 122 GP-2, Appendix 1, Reactor Start-up and Heat-up, Revision 37 GP-3, Normal Plant Shutdown, Revision 123 GP-6.1, Shutdown Operations, Refueling, Core Alterations and Core Off-Loading, Revision 136 GP-6.2, Shutdown Operations - Shutdown Condition Tech Spec Actions, Revision 42 M-098-002, Reactor Enclosure Crane Frequent Inspection and Maintenance, Revision 13 ON-120, Fuel Handling Problems, Revision 16 OP-AA-103-102, Watchstanding Practices, Revision 7 ST-4-098-320-0, Reactor Enclosure Overhead Crane Interlock Operability Verification, Revision 8

ST-6-107-640-1, Reactor Vessel Temperature and Pressure Monitoring, Revision 44 S32.1.A, Synchronizing Main Generator to Grid, Revision 24 S53.3.A, Direct Makeup to Fuel Storage Pool, Revision 15 S57.5.A, De-inerting and Purging Primary Containment, Revision 42 S98.1.A, Operation and Pre-Use Inspection of Reactor Enclosure Overhead Crane 00-H201, Revision 9 Issue Reports and Action Requests IR 147878, Lowering Skimmer Surge Tank Level IR 148153, RPV Water Clarity Degraded After ADHR Placed in Service Attachment

A-8 IR 601910, Drainage System Clogged IR 694798, LGS Actions for Hope Creek Nozzle Defect IR 709152, Results of Weld Re-Review on the LGS U/1 N5A Nozzle to Safe IR 709747, Results of Weld Re-Review Based on Hope Creek OE IR 710814, Ops Eva I Not Completed Within Three Days IR 722237, Identified Leakage at Flange to PSV-044-207A (Room 579)

IR 722902, F'loor Drain Clog Found During Verification

• IR 725883, Funnel Drains in D23 Bay Back Up IR 725946, FME Found on Top of Fuel Channel IR 732554, Unplanned Entry in TS Action Due to Human Performance IR 734644, 2A Reactor Recirc Pump Seal Stage Flow Hi/Lo IR 738110, Channel Distortion Testing Required due to LaSalle Results IR 743868, HV-051-1F041C Valve Did Not Stroke IR 743869, Drywell Head Lift Delay IR 744027, 1R12 - Refuel Floor Crane - Zero Span Calibration IR 744254, HV-51-1F041C Disc Indication Failed to Illuminate IR 747235, ON-120 Entry for Fuel Handling Problem Miscellaneous 8031-M-38-8, Overhead Handling Systems Review (NUREG-0612 Compliance), Revision 6 DNA History Plot, Skimmer Surge Tank Level 03/09/2008-03/10/2008 ECR LG 08-00051, Need Camera for 2A Recirc Limerick Generating Station UFSAR Section 9,1,5 Operator Logs, dated 03/01/2008 through 03/20/2008 Quick Human Investigation Report, Refuel Floor ARM Alarms and Per~onnel Evacuation after Reactor Vessel Water Observed to be Bubbling, IR 747235 Technical Specification 3,9,7, Crane Travel- Spent Fuel Storage Pool Troubleshooting, Rework, and Testing (TRT) 08-29 Section 1R22: Surveillance Testing ST-6-092-322-2 D22 Diesel Generator LOCAlLoad Reject Testing and Fast Start Operability Test Run, Revision 12 ST-4-051-311-2 A RHR Auto Close SII Contact, Revision 2 ST-4-LLR-051-1, Main Steam Line 'C', Revision 10, completed 03/06/2008 ST-6-051-231-2 A RHR Pump, Valve and Flow Test, Revision 55 Section 20S1: Access Control to Radiologically Significant Areas Procedures RP-LG-101-1001, RP Technician Duty Positions, Revision 0 RP-AA-210, Dosimetry Issue, Usage, and Control, Revision 11 RP-AA-250, External Dose Assessments from Contamination, Revision 4 RP-LG-300-102, Removing Iterns from the Spent Fuel Pool, Reactor Cavity, Equiprnent Pit, or Cask Pit, Revision 2 RP-AA-350, Personnel Contamination Monitoring, Decontamination, and Reporting, Revision 7 RP-AA-376, Radiological Postings, Labeling, and Markings, Revision 2 RP-AA-400, ALARA Program, Revision 4 RP-LG-400-1003, Emergent Dose Control and Authorization, Revision 2 RP-LG-400-1002, Departrnent Dose Zealot, Revision 2 RP-AA-401, Operational ALARA Planning and Controls, Revision 7 Attachrnent

A-9 RP-AA-403, Administration of the Radiation Work Permit Program, Revision 1 RP-AA-460, Controls for High and V,?-ry High Radiation Areas, Revision 13 RP-LG-460-1016, Radiation Protection Controlled Keys, Revision 6 CY-LG-120-1301, Outage Cobalt Limits, Revision 2 RT-0-100-460-0, High Radiation and Locked High Radiation Door Preventative, Revision 3 RP-AA-12, Internal Dose Control Program Description, Revision 0 RP-AA-201-1001, Radiological Instruction Sheet for Escorted Visitors, Revision 0 RP-AA-203, Exposure Control and Authorization, Revision 3 RP-AA-210, Dosimetry Issue, Usage, and Control, Revision 11 RP-AA-214, Area TLD Surveillance, Revision 2 RP-AA-220, Bioassay Program, Revision 5 RP-AA-222, Methods for Estimating Internal Exposure from In Vivo and In Vitro Bioassay Data, Revision 3 RP-AA-250, External Dose Assessments from Contamination, Revision 4 RP-AA-270, Prenatal Radiation Exposure, Revision 3 RP-LG-300-102, Removing Items from the Spent Fuel Pool, Reactor Cavity, Equipment Pit, or Cask Pit, Revision 2 RP-AA-300-1002, Electron Capture Isotope Control, Revision 0 RP-AA-301, Radiological Air Sampling Program, Revision 2 RP-AA-350, Personnel Contamination Monitoring, Decontamination, and Reporting, Revision 7 RP-AA-376, Radiological Postings, Labeling, and Markings, Revision 2 RP-AA-400, ALARA Program, Revision 5 RP-LG-400-1003, Emergent Dose Control and Authorization, Revision 2 RP-LG-400-1002, Department Dose Zealot, Revision 2 RP-LG-401-1001, Reactor Cavity and Equipment Pit Decontamination, Revision 3 RP-AA-401, Operational ALARA Planning and Controls, Revision 9 RP-AA-403, Administration of the Radiation Work Permit Program, Revision 1 RP-AA-460, Controls for High and Very High Radiation Areas, Revision 13 RP-AA-462, Controls for Radiographic Operations, Revision 5 RP-AA-500, Radioactive Material Control, Revision 13 RP-LG-460-1016, Radiation Protection Controlled Keys, Revision 6 RP-LG-400-1 021, Reactor Cavity Draindown, Revision 1 RP-LG-500-1012, Breach ahd Control of Radioactive Systems, Revision 1 CY-LG-120-1301, Outage Cobalt Limits, Revision 2 RT-0-100-460-0, High Radiation and Locked High Radiation Door Preventative Maintenance Inspection, Revision 3 ON-120, Fuel Handling Problems, Revision 16 Issue Reports 730548,741338,730635,731039,731101,744001, 730803, 721658, 721661, 721779, 719994, 637874, 747640, 747637, 747482, 747642, 747752, 747763, 744384, 746946, 740534, 745127, 747235,746784,746968, 746920, 746944,673841,618357,603753,624388,604735,699859, 643407,617899,659050,605345,604735, 707597, 701801,673816,673701,673706, 718927 ALARAPlans 2008-01, Radiography U-1 Rx 201' el Room 203 RHR HBB-145-1 2008-03, 1R12 CRD Exchange and Support Work 2008-05, U-1 Rx 201' elevations, AlC and BID RHR Rooms, ESW Header Pipe Replacement Modification 2008-07, Radiography U-1 DIW, HV-051-1F50B Valve Replacement 2008-24, Replace HV-51-1F050B, Unit 1 OW Attachment

A-10 Work-in-progress Reviews:

Install and Remove Drywell Shielding 1R12 Install and Remove Drywell Scaffolding 1R12 Install and Remove Altemate Decay Heat Removal Spool Piece Nuclear Oversight Reports Audit NOSA-LlM-07-06 (AR 651837)

Objective Evidence Reports dated 05/09/07, 05/23/07, 05/31/07, 06/20107, 07/30107, 08/01/07, 08106/07,08/16/07, 09/14/07,10/09/07,10/16/07,11/05/07,11/07/07,12105/07, 12113/07,12107/07 Nuclear Oversight Objective Evidence Reports Dated: 01/04/2008, 01/30/2008,02/08/2008,02119/2008 Station ALARA Council Meeting Minutes Meeting Nos. :2008-07,2008-06,2008-05 Meeting Nos.: 2007-08/09110111/12/13/14/15/16/17 and 2008-01 Miscellaneous Reports 2006-2011 Exposure Reduction Plan Dose and Dose Rate Alarm Report for period March 1 -10, 2008 Electronic Dosimetry DoselDose Rate Alarm Basis Daily Unit 1 Outage Project Dose Reports Section 40A1: Performance Indicator (PI) Verification Miscellaneous \

Reactor Oversight Program MSPI Bases Document Limerick Generating Station, Revision 1 .

MSPI Derivation Report for Unit 1 and Unit 2 HPCI Operator Logs, dated 07/01/2007 through 12/31/2007 Section 40A3: Event Follow-up Procedures ON-120, Fuel Handling Problems, Revision 16 FH-105, Core Component Movement-Core Transfers, Revision 42 LIST OF ACRONYMS ADAMS Agencywide Documents Access Management System ADHR alternate decay heat removal ALARA as low as reasonably achievable AP ALARA Plans AR action request ARC alarm response card ASME American Society of Mechanical Engineers ATWS anticipated transient without a scram CAP Corrective Action Program CEDE committed effective dose equivalent CFR Code of Federal Regulations CNO Chief Nuclear Officer CREFAS control room emergency fresh air system Attachment

A-11 CST condensate storage tank OM dissimilar metal ECR engineering change request EDG emergency diesel generator EED Exelon Energy Delivery EHC electrohydraulic control EPRI Electric Power Research Institute ESW emergency service water GL Generic Letter HDR high dose rate HPCI high pressure coolant injection HRA high radiation area IMC Inspection Manual Chapter IR issue report lSI in-service inspection IWI in-vessel visual inspection LER Licensee Event Report LHRA locked high radiation area LPCI low pressure coolant injection system NCV non-cited violation NEI Nuclear Energy Institute NRC Nuclear Regulatory Commission P&ID piping and instrumentation drawing PARS Publicly Available Records PI performance indicator PMT post-maintenance test RCA radiologically controlled area RCIC reactor core isolation cooling RCWP reactor cavity work platform RG Regulatory Guide RHR residual heat removal RHRSW residual heat removal service water RRCS redundant reactivity control system RRP reactor recirculation pump RRP reactor recirculation pump RT radiographic testing RTP rated thermal power RWP radiation work permit RWST refueling water storage tank SBGT standby gas treatment SOP significance determination process SRM source range monitor SSC structure, system, component SST skimmer surge tank ST surveillance test TEDE total effective dose equivalent TS technical specification UFSAR updated final safety analysis report UT ultrasonic testing VHRA very high radiation area Attachment

UNITED STATES NUCLEAR REGULATORY COMMISSION REGION I 475 ALLENDALE ROAD KING OF PRUSSIA, PA 19406-1415

• August 13, 2008 Mr. Charles G. Pardee Chief Nuclear Officer (CNO) and Senior Vice President Exelon Generation Company, LLC Chief Nuclear Officer (CNO)

AmerGen Energy Company, LLC 200 Exelon Way Kennett Square, PA 19348

SUBJECT:

LIMERICK GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000352/2008003 AND 05000353/2008003

Dear Mr. Pardee:

l On June 30, 2008, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your Limerick Generating Station Units 1 and 2. The enclosed integrated inspection report documents the inspection results which were discussed on July 7, 2008, with Mr. C. Mudrick and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

This report documents one NRC-identified finding of very low safety significance (Green).

The finding was determined to involve a violation of an NRC requirement. Additionally, two licensee-identified violations which were determined to be of very low safety significance are listed in this report. However, because of the very low safety Significance and because they are entered into your corrective action program (CAP), the NRC is treating these findings as non-cited violations (NCVs), consistent with Section VI.A.1. of the NRC Enforcement Policy.

If you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administration, Region 1; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-001; and the NRC Resident Inspector at the Limerick facility. .

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the Enclosure 9

C. Pardee 2 NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRC's document system (ADAMS). ADAMS is accessible from the NRC Website at hUp:/Iwww.nrc.gov/reading-rm/adams.html(the Public Electronic Reading Room).

Sincerely, IRAJ Paul G. Krohn, Chief Projects Branch 4 Division of Reactor Projects Docket Nos: 50-352, 50-353 License Nos: NPF-39, NPF-85 EnClosure: Inspection Report 05000352/2008003 and 05000353/2008003 w/AUachment: Supplemental Information cc w/encl:

C. Crane, Executive Vice President and Chief Operating Officer, Exelon Generation M. Pacilio, Chief Operating Officer, Exelon Generation Company, LLC C. Mudrick, Site Vice President - Limerick Generating Station E. Callan, Plant Manager, Limerick Generating Station R. Kreider, Regulatory Assurance Manager R. DeGregorio, Senior Vice President, Mid-Atlantic Operations K. Jury, Vice President, Licensing and Regulatory Affairs P. Cowan, Director, Licensing D. Helker, Licensing B. Fewell, Associate General Counsel Correspondence Control Desk D. Allard, Director, PA Department of Environmental Protection J. Johnsrud, National Energy Committee, Sierra Club Chairman, Board of Supervisors of Limerick Township J. Powers, Director, PA Office of Homeland Security R. French, Director, PA Emergency Management Agency

C. Pardee 3 NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRC's document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html(the Public Electronic Reading Room).

Sincerely, IRA!

Paul G. Krohn, Chief

• Projects Branch 4 Division of Reactor Projects Distribution w/enci: (via E-mail)

S. Collins, RA M. Dapas, DRA D. Lew, DRP J. Clifford, DRP P. Krohn, DRP R. Fuhrmeister, DRP T. Setzer, DRP E. DiPaolo, DRP, Senior Resident Inspector C. Bickett, DRP, Resident Inspector L. Pinkham, Resident OA S. William, RI, OEDO H. Chernoff, NRR P. Bamford, PM, NRR J. Hughey, PM, Backup I ROPreports@nrc.gov Region I Docket Room (with concurrences)

ML082261341 SUNSI REVIEW COMPLETE: PGK (Reviewer's Initials)

DOCUMENT: G:IDRPIBRANCH4IDRAFT INSPECTION REPORTS FOR BR 4 FOR 200812ND QTR 2008 DRAFT REPORTSILIMERICKlLlM 2008-003.DOC After declaring this document "An Official Agency Record" it will be released to the Public To receive a copy of this document, indicate in the box: "C* =Copy without attachment/enclosure "E- =Copy with attachment/enclosure -N" =No copy OFFICE RIIDRP I RIIDRP I N RIIDRP I NAME EDiPaolol PGK for RFuhrmeisterl RF PKrohn/PGK DATE OS/12 IDS OS/09/0S OS/13 IDS OFFICIAL RECORD COpy

1 u.s. NUCLEAR REGULATORY COMMISSION REGION 1 Docket Nos: 50-352, 50-353 License Nos: NPF-39, NPF-85 Report No: 05000352/2008003 and 05000353/2008003 Licensee: Exelon Generation Company, LLC Facility: Limerick Generating Station, Units 1 & 2 Location: Sanatoga, PA 19464 Dates: April 1, 2008 through June 30, 2008 Inspectors: E. DiPaolo, Senior Resident Inspector C. Bickett, Resident Inspector T. Moslak, Health Physicist (Section 2PS2)

Approved by: Paul G. Krohn, Chief Projects Branch 4 Division of Reactor Projects Enclosure

2 TABLE OF CONTENTS

SUMMARY

OF FINDINGS ........................................................~ ................................................ 3 REPORT DETAILS ..................................................................................................................... 4

1. REACTOR SAFETY ........................................................................................................... 4 1R01 Adverse Weather Protection ................................................................................... 4 1R04 Equipment Alignment .............................................................................................. 5 1R05 Fire Protection ......................................................................................................... 5 1R06 Flood Protection Measures .................................................................................... 6 1R11 Licensed Operator Requalification Program ........................................................... 6 1R12 Maintenance Effectiveness ..................................................................................... 7 1R13 Maintenance Risk Assessments and Emergent Work Control ................................ 7 1R15 Operability Evaluations ............................................................................................ 8 1R19 Post-Maintenance Testing ............................................................,......................... 8 1R22 Surveillance Testing ............................................................................................... 9 EP6 Drill Evaluation ....................................................................................................... 9

2. RADIATION SAFETY ....................................................................................................... 10

4. OTHER ACTIVITIES ................................................... ,........ \............................................ 12 40A1 Performance Indicator (PI) Verification ................................................................. 12 40A2 Identification and Resolution of Problems ............................................................. 13 40A3 Event Follow-Up ................................................................................................... 16 40A6 Meetings, Including Exit. ........................................................................................ 17 40A7 Licensee-Identified Violations ............................................... ,................................ 17 SUPPLEMENTAL INFORMATION ......................................................................................... A-1 KEY POINTS OF CONTACT .................................................................................................. A-1 LIST OF ITEMS OPENED, CLOSED, AND DiSCUSSED ....................................................... A-1 LIST OF DOCUMENTS REVIEWED .................................................................. ,................... A-2 Enclosure

3

SUMMARY

OF FINDINGS IR 0500035212008003, 05000353/2008003; 04/01/2008 - 06/30/2008; Limerick Generating Station, Units 1 and 2; Problem Identification and Resolution.

The report covered a three-month period of inspection by resident inspectors and an announced inspection by a regional health physics inspector. One NRC-identified Green finding, determined to be a non-cited violation (NCV), was identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process (SOP)." Findings for which the SOP does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight," Revision 4, dated December 2006.

A. NRC-Identified and Self-Revealing Findings Cornerstone: Barrier Integrity

• Green. The inspectors identified an NCV of Title 10 of the Code of Federal Regulations, Part 50 (10CFR50), Appendix B, Criterion XVI, "Corrective Action," for not correcting a condition adverse to quality associated with safety-related motor operated valve motor control center auxiliary contact switches in a timely manner following the failure ofthe Unit 1 Core Spray Loop A test bypass primary containment isolation valve (HV-052-1F015A) to close on August 3,2006. As a result, the Unit 2 Reactor Core Isolation Cooling (RCIC) turbine exhaust line vacuum breaker outboard primary containment isolation valve (HV-049-2F080) experienced a similar failure to close on June 4, 2008.

The finding was more than minor because it was associated with the structures, systems, and components and barrier containment performance attribute of the Barrier Integrity cornerstone and affected the objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents and events. The inspector assessed the finding using Phase 1 of IMC 0609, Appendix A, "Significance Determination Process for Reactor Inspection Findings for At-Power Situations" and determined the finding to be of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment. This finding has a cross-cutting aspect of Problem Identification and Resolution because Exelon did not take appropriate corrective actions to address safety issues and adverse trends in a timely manner, commensurate with the safety significance and complexity (P.1 (d)).

(Section 40A2)

B. Licensee-Identified Violations Violations of very low safety significance, which were identified by Exelon, have been reviewed by the inspectors. Corrective actions taken or planned by Exelon have been entered into their corrective action program. These violations and corrective actions are listed in Section 40A7 of this report.

Enclosure

4 REPORT DETAILS Summary of Plant Status Unit 1 began the inspection period operating at full rated thermal power (RTP). On April 5, 2008, operators reduced power to approximately 85 percent to facilitate a control rod pattern adjustment and to return control rod hydraulic control units to service following maintenance.

• Full RTP was aChieved on April 6, 2008. A planned downpower to approximately 77 percent was performed on May 16, 2008, to facilitate control rod scram time testing, main turbine valve testing, and secondary plant maintenance. Full RTP was achieved on May 17, 2008. Unit 1 operated at full RTP for the remainder of the inspection period.

Unit 2 began the inspection period operating at full RTP. On April 26, 2008, operators reduced power to approximately 25 percent to facilitate main steam isolation and main turbine valve testing, control rod scram time testing, and to perform hot weather readiness preventive maintenance. Full RTP was achieved on April 27, 2008. On May 22, 2008, operators reduced power to approximately 60 percent to facilitate main turbine valve testing and to perform secondary plant maintenance. Power was restored to full RTP on May 23, 2008. Unit 2 operated at full RTP for the remainder of the inspection period.

1. REACTOR SAFETY Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integritv 1R01 Adverse Weather Protection (71111.01 - 2 samples) \

.1 Summer Readiness of Offsite and Alternate Alternating Current rAC) Power Systems

a. Inspection Scope The inspectors performed a review of plant features and procedures for the operation and continued availability of the offsite and alternate At power system to evaluate the readiness of the systems prior to seasonal high grid loading. The inspectors reviewed Exelon's procedures affecting these areas and the communications protocols between the transmission system operator and Exelon. This review focused on verifying that appropriate information is exchanged when grid conditions arise that could impact the offsite power system. The inspector assessed whether appropriate procedures and protocols were established and implemented to monitor and maintain availability and reliability of both the offsite AC power system and the onsite alternate AC power system.

Documents reviewed are listed in the Attachment.

b. Findings No findings of significance were identified .

.2 External Flooding

a. Inspection Scope The inspectors performed a review of extemal flood protection barriers associated with the Emergency Diesel Generator (EDG) fuel oil storage tanks and the safety-re.lated Enclosure

5 service water underground manholes. The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) to identify design features for coping with external flooding. The inspectors performed a walkdown of accessible fuel oil storage tank vaults and underground manholes associated with the service water system to verify that design features for the protection of water intrusion were installed and functional. The inspector reviewed preventive maintenance and site procedures to verify that commitments associated with the protection of water intrusion for the areas were properly established. Documents reviewed are listed in the Attachment.

b. Findings No findings of significance were identified.

1R04 Eguipment Alignment Partial Walkdown (71111.040 - 3 samples)

a. Inspection Scope The inspectors performed a partial walkdown of the plant systems listed below to verify the operability of redundant or diverse trains and components when safety-related equipment in the opposite train was either inoperable, undergoing surveillance testing, or potentially degraded. The inspectors used plant Technical Specifications (TS), Exelon operating procedures, plant piping and instrumentation drawings (P&IDs), and the USFAR as guidance for conducting partial system walkdowns. The inspectors reviewed the alignment of system valves and electrical breakers to ensure proper in-service or standby configurations as described in plant procedures and drawings. During the walkdown, the inspectors evaluated material condition and general housekeeping of the system and adjacent spaces. The documents reviewed are listed in the Attachment.

The inspectors performed walkdowns of the following areas:

• 'A' Control Room Emergency Fresh Air System (CREFAS) with'S' CREFAS out-of-service for planned maintenance;

• D22 EDG following return-to-service due to fuel oil storage tank inspection; and

• 2 'A' and 'C' Residual Heat Removal (RHR) pumps with 2 'D' RHR pump out of service for planned maintenance.

b. Findings No findings of Significance were identified.

~ 1R05 Fire Protection Fire Protection - Tours (71111.050 - 5 samples)

a. Inspection Scope The inspectors conducted a tour of the five areas listed below to assess the material condition and operational status of fire protection features. The inspectors verified that combustibles and ignition sources were controlled in accordance with Exelon's administrative procedures, fire detection, and suppression equipment was available for Enclosure

6 use, and that passive fire barriers were maintained in good material condition. The inspectors also verified that station personnel implemented compensatory measures for out-of-service, degraded, or inoperable fire protection equipment in accordance with the station's fire plan. The documents reviewed are listed in the Attachment. The inspectors toured the following areas:

• Spray Pond Pumphouse;

• Auxiliary Equipment Room and Remote Shutdown Panel Room;

• Diesel-Driven Fire Pump Room;

• D22 EDG Fuel Oil Storage Tank (FOST) Vault; and

• D21 EDG and Fuel Oil/Lube Oil Tank Room.

b. Findings No findings of significance were identified.

1R06 Flood Protection Measures (71111.06 - 1 sample)

a. Inspection Scope The inspectors reviewed the UFSAR and related flood analysis document to identify areas that can be affected by internal flooding, to identify features designed to alert operators of a flooding event, and to identify features designed for coping with internal flooding. The inspectors performed a walkdown of Units 1 and 2 Emergency Core Cooling Pump Rooms (Reactor Buildings, Elevation 177'). The inspectors observed

\ flood protection features to assess their ability to minimize the impact of a flooding event.

The inspector verified that periodic preventive maintenance was established for flood detection equipment in these areas. The inspector performed a review of operator actions contained in off-normal procedures for flooding to verify that they can reasonably be used to achieve desired actions. Documents reviewed are listed in the Attachment.

b. Findings No findings of significance were identified.

1R11 Licensed Operator Regualification Program (71111.110 -1 sample)

a. Inspection Scope On April 29, 2008, the inspectors evaluated licensed operator requalification simUlator scenarios on two operating crews. The scenario tested the operators' ability to respond to various failures, including the loss of power to plant equipment, control rod malfunctions, a fuel failure, and a steam leak outside containment. The inspectors observed licensed operator performance including operator critical tasks that measure operator actions required to ensure the safe operation of the reactor and protection of the nuclear fuel and primary containment barriers. The inspectors also assessed group dynamics and supervisory oversight to verify the ability of operators to properly identify and implement appropriate TS actions, regulatory reports, and notifications. The inspectors observed and reviewed the training evaluators' grading and critiques and assessed whether appropriate feedback was provided to the licensed operators. The documents reviewed are listed in the Attachment.

Enclosure

7

b. Findings No findings of significance were identified.

1R12 Maintenance Effectiveness (71111.12 - 2 samples)

a. Inspection Scope The inspectors evaluated Exelon's work practices and follow-up corrective actions for structures, systems, and components (SSCs) and identified issues to assess the effectiveness of Exelon's maintenance activities. The inspectors reviewed the performance history of risk Significant SSCs and assessed Exelon's extent-of-condition determinations for those issues with potential common cause or generic implications to evaluate the adequacy of the station's corrective actions. The inspectors assessed Exelon's problem identification and resolution actions for these issues to evaluate i whether Exelon had appropriately monitored, evaluated, and dis positioned the issues in accordance with Exelon procedures and the requirements of 10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance." In addition, the inspectors reviewed selected SSC classifications, performance criteria and goals, and Exelon's corrective actions that were taken or planned, to evaluate whether the actions were reasonable and appropriate. The documents reviewed are listed in the Attachment. The inspectors performed the following samples:

• Issue Report (IR) 707564, Maintenance Rule a(1) Determination for Instrument Air System; and

• IR 671975, HV-055-2F093 Failed to Operate from Handswitch.

b. Findings No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13 - 6 samples)

a. Inspection Scope The inspectors evaluated the effectiveness of Exelon's maintenance risk assessments required by 10 CFR 50.65(a)(4). This inspection included discussion with control room operators and risk analysis personnel regarding the use of Exelon's on-line risk monitoring software. The inspectors reviewed equipment tracking documentation, daily work schedules, and performed plant tours to gain assurance that the actual plant configuration matched the assessed configuration. Additionally, the inspectors verified that Exelon's risk management actions, for both planned and emergent work, were consistent with those described in Exelon procedure, ER-AA-600-1042, "On-Line Risk Management." The documents reviewed are listed in the Attachment. Inspectors reviewed the following samples:

• Unit 2 RHR Heat Exchanger Repairs with a Control Rod Drive Pump Out-of-Service during Work Week 0815;

• IR 762240, Unit 2 A RHR Heat Exchanger Bypass Valve Failure (HV-C-051-2F048A); .

Enclosure

8

• IR 737066, Unit 2 Main Turbine Valve Testing following Abnormal Bypass Valve Response;

• Emergent Work on Reactor Enclosure Recirculation System (RERS) during 'B' CREFAS Out of Service for Planned Maintenance;

• Emergent Work on 'A' CREFAS during Unit 1 'A' Core Spray (CS) System Outage Window (SOW), D22 EDG FOST Cleaning, and D11 EDG SOW; and

• IR 790935, Emergent Work on D14 EDG due to Load and Voltage Transient during Post-Maintenatlce Testing.

b. Findings No findings of significance were identified.

1R15 Operability Evaluations (71111.15 - 5 samples)

a. Inspection Scope For the five operability evaluations described below, the inspectors assessed the technical adequacy of the evaluations to ensure that Exelon properly justified TS operability and verified that the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors reviewed the UFSAR to verify that the system or component remained available to perform its intended safety function. In addition, the inspectors reviewed compensatory measures implemented to ensure that the measures worked and were adequately controlled. The inspectors also reviewed a sample of issue reports to verify that Exelon identified and corrected deficiencies associated with operability evaluations. The documents reviewed are listed in the Attachment. The inspectors performed the following assessments:

• IR 756914, Unit 1C Safety/ReliefValve Second Stage Temperature is Reading Two Degrees Low; .

• .IR 765052, D12 FOST Mechanical Indictor Stuck;

• IR 766331, Unit 2A Suppression Pool Cooling Retum Valve (HV-051-2F024A) Stem-to-Disc Separation;

• IR 758875, D23 EDG Jacket Water and Lubricating Oil Temperature Switches Found Out-of-Calibration; and

• IR 780592, 'A' Flow Balance 89-13 Margin Review of CS Unit Coolers.

b. Findings No findings of significance were identified.

1R19 Post-Maintenance Testing (71111.19 -7 samples)

a. Inspection Scope The inspectors reviewed the seven post-maintenance tests (PMTs) listed below to verify that procedures and test activities ensured system operability and functional capability.

The inspectors reviewed Exelon's test procedures to verify that the procedures adequately tested the safety functions that may have been affected by the maintenance activity, and that the acceptance criteria in the procedures were consistent with information in the licensing and design basis documents. The inspectors also witnessed Enclosure

9 the test or reviewed test data to verify that the results adequately demonstrated restoration of the affected safety functions. The documents reviewed are listed in the Attachment. The inspectors performed the following samples:

• C0224662, Unit 2A RHR Heat Exchanger Bypass Valve (HV-C-051-2F048A)

Repairs;

• C0223007, Unit 2A RHR Suppression Pool Cooling Return Valve (HV-051-F024A)

Repairs;

• ST-6-076-250-1 following Unit 1A RERS SOW;

• R1096864, Overhaul Unit 1 Control Rod Drive Hydraulic Control Unit 26-03 Waterside Components;

• ST-6-076-250-2, Standby Gas Treatment System (SGTS) and RERS Flow Test following 2B RERS SOW;

• High Pressure Coolant Injection (HPCI) Valve Test and Pump, Valve and Flow Test following Unit 1 HPCI SOW; and

• C0225543, D14 EDG Troubleshooting and Repairs following load Transient during Testing.

b. Findings No findings of significance were identified.

1R22 Surveillance Testing (71111.22 - 5 samples)

a. Inspection Scope The inspectors witnessed the performance and reviewed test data for five surveillance tests (STs) that are associated with risk-significant SSCs. The review verified that Exelon personnel followed TS requirements and that acceptance criteria were appropriate. The inspectors also verified that the station established proper test conditions, as specified in the procedures, that no equipment preconditioning activities occurred, and that acceptance criteria had been met. The documents reviewed are listed in the Attachment. The inspectors reviewed STs for the following systems and components:

• ST-6-092-315-2, D21 Diesel Generator Fast Start Operability Test Run;

• ST-6-092-316-1, D12 Diesel Generator Fast Start Operability Test Run;

• ST 092-115-1, D11 Diesel Generator loss of Coolant Accident floss of Coolant Projection Test;

• ST-6-049-230-1, RCIC Pump, Valve, and Flow Test; and

• ST 076-250-1, SBGT and RERS Flow Test.

b. Findings No findings of significance were identified.

EP6 Drill Evaluation (71114.06 - 3 samples)

a. Inspection Scope Enclosure

10 The inspe~tors observed the training evolution and emergency preparedness drills listed below to assess Exelon's emergency response organization's (ERO) implementation of the Limerick emergency plan and implementing procedures. The inspectors reviewed ERO's response to simulated degraded plant conditions to identify weaknesses and deficiencies in classification, notification, and PAR development activities. In addition, the inspectors assessed licensed operator performance required to ensure the safe operation of the reactor and the protection of the nuclear fuel and primary containment barriers. The inspectors observed Exelon's controller end evaluators' critiques of the drill to evaluate Exelon's identification of weaknesses and deficiencies. The inspectors compared inspector observed weaknesses with those identified in Exelon's drill critique to verify whether Exelon adequately identified weaknesses and deficiencies at an appropriate threshold. The inspector verified that the licensee appropriately assessed ERO performance with regard to activities contributing to the Drill and Exercise Performance (DEP) performance indicator training evolution and drills. The documents reviewed are listed in the Attachment. The inspectors assessed the following samples:

• Simulator Training Exercise conducted on April 29, 2008;

• Emergency Preparedness Drill conducted on June 3, 2009; and

• Emergency Preparedness Drill conducted on June 18, 2008.

b. Findings No findings of significance were identified.

2. RADIATION SAFETY

\

Cornerstone: Public Radiation Safety 2PS2 Radioactive Material Processing and Transportation (71122.02 - 6 samples)

a. Inspection Scope During the period June 2 - 6, 2008, the inspector conducted the following activities to verify that Exelon's radioactive material processing and transportation programs complied with the requirements of 10 CFR 20, 61, 71, and Department of Transportation (DOT) regulations 49 CFR 170-189. The documents reviewed are listed in the Attachment.

Radioactive Waste Systems Walkdown The inspector walked down accessible portions ofthe radioactive liquid processing systems and site radwaste storage areas with the Radwaste Systems Engineer and a Radiation Protection Specialist, respectively. During the tour, the inspector evaluated if the systems and facilities were consistent with the descriptions contained in the UFSAR and the Process Control Program (PCP), evaluated the general material conditions of the systems and facilities, and identified any changes to the systems. The inspector reviewed the current processes for transferring radioactive resin/sludge to shipping containers, and the subsequent de-watering process.

Also during this tour, the inspector walked down portions of radwaste systems that are no longer in service or abandoned in place, and discussed the status of administrative Enclosure

11 and physicai'controls for these systems including components of the radwaste evaporators and centrifuges.

The inspector visually inspected various radioactive material storage locations with the Radiation Protection Specialist, including areas of the Radwaste Building, outside yard locations within the Protected Area, and the on-site disposal site (10 CFR 20,2002 area) to evaluate material conditions.

Waste Characterization and Classification The inspection included a selective review of the waste characterization and classification program for regulatory compliance, including:

• The radio-chemical sample analytical results for various radioactive waste streams;

• The development of scaling factors for hard-to-detect radio-nuclides from radio-chemical data;

• The methods and practices to detect changes in waste streams; and

• The characterization and classification of waste relative to 10 CFR 61.55 and the determination of DOT shipment subtype per 49 CFR 173.

Shipment Preparation The inspection included a review of radioactive waste program records, shipment preparation procedures, training records, and observations of jobs-in-progress, including:

• Reviewing radwaste and radioactive material shipping logs for calendar years 2006, 2007, and 200B;

• Verifying that training was provided to appropriate personnel responsible for classifying, handling, and shipping radioactive materials, in accordance with Bulletin 79-19 and 49 CFR 172 Subpart H;

• Verifying that appropriate NRC (or agreement state) license authorization was current for shipment recipients for recent shipments;

• Observing a radwaste Shipping Supervisor provide briefing instructions to a driver for shipment MW-OB-024; and

• Verifying compliance with the relevant Certificates-of-Compliance and related procedures for shipping casks.

Shipment Recoras The inspector selected and reviewed records associated with five Type B shipments of radioactive material made since the last inspection of this area. The shipment numbers were MW-07-014, MW-07-015, MW-07-016, MW-07-017, and MW-07-01B. The inspector reviewed the following aspects of the radioactive waste packaging and shipping activities:

• Implementation of applicable shipping requirements including proper completion of manifests;

• Implementation of speCifications in applicable certificates-of-compliance, for the approved shipping casks, including limits on package contents;

• Verification that dewatering criteria was met; Enclosure

12

• Classification of radioactive materials relative to *10 CFR 61.55 and 49 CFR 173;

• Labeling of containers relative to package dose rates;

• Radiation and contamination surveys of the packages;

• Placarding of transport vehicles;

• Conduct of vehicle checks;

• Providing of emergency instructions to the driver;

• Completion of shipping papers; and

• Notification by the recipient that the radioactive materials have been received and

• disposed of.

Identification and Resolution of Problems The inspector reviewed the 2007 Annual Radioactive Effluent Release Report, relevant

• Issue Reports, a Nuclear Oversight Audit, a self-assessment report and recent Yard Area Rad Material Inspection reports. Through this review, the inspector assessed Exelon's threshold for identifying problems, and the promptness and effectiveness of the resulting corrective actions. This review was conducted against the criteria contained in 10 CFR 20.1101(c) and Exelon's procedures.

b. Findings No findings of significance were identified.

4. OTHER ACTIVITIES 40A1 Performance Indicator (PI) Verification (71151 - 6 samples) I

a. Inspection Scope The inspectors sampled Exelon's submittal of the initiating events and mitigating systems performance indicators listed below to verify the accuracy of the data recorded from the fourth quarter of 2007 through the first quarter of 2008. The inspectors utilized performance indicator definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, "Regulatory Assessment Performance Indicator Guideline, " Revision 5, to verify the basis in reporting for each data element. The inspectors reviewed various documents, including portions of the main control room logs, issue reports, power history curves, work orders, and system derivation reports. The inspectors also discussed the method for compiling and reporting performance indicators with cognizant engineering personnel and compared graphical representations from the most recent PI report to the raw data to verify that the report correctly reflected the data. The documents reviewed are listed in the Attachment.

Cornerstone: Mitigating Systems (6 samples)

• Units 1 and 2 Mitigating Systems Performance Index, Emergency AC Power System

• Units 1 and 2 Mitigating Systems Performance Index, Heat Removal System

• Units 1 and 2 Safety System Functional Failures

b. Findings No findings of significance were identified.

Enclosure

13 40A2 Identification and Resolution of Problems (71152 - 2 Annual Samples; 1 Semi-Annual Trend Review)

.1 Review of Items Entered into the Corrective Action Program (CAP)

As required by Inspection Procedure 71152, "Identification and Resolution of Problems,"

and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors screened all items entered into Limerick's corrective action program. The inspectors accomplished this by reviewing each new condition report, attending management review committee meetings, and accessing Exelon's computerized database .

.2 Semi-Annual Review to Identify Trends

a. Inspection Scope As required by inspection procedure 71152, "Identification and Resolution of Problems,"

the inspectors performed a review of Exelon's CAP and associated documents to identify whether trends existed that would indicate a more significant safety issue. The review considered the period of January through June 2008 and was focused on repetitive equipment issues. The results of routine inspector CAP item screening, Exelon's trending efforts, and human performance results were also considered. The inspectors reviewed issues documented outside the normal CAP such as Plant Health Committee reports including the Top Ten Equipment Issues List, the Plant Health Committee Issues List, and the Open Action Items List. The inspectors compared and contrasted their results with the results contained in the Limerick Generating Station Performance Trending reports for the first quarter 2008.

b. Assessment and Observations No findings of significance were identified. The review did not reveal any trends that could indicate a more significant safety issue. The inspectors assessed that Exelon was identifying issues at a low threshold and entering the issues into the CAP for resolution .

.3 Annual Sample: 2A RHR High Discharge Pressure Alarm

a. Inspection Scope The inspectors reviewed Limerick's corrective actions associated with IR 709219 regarding a 2A RHR pump discharge high pressure alarm. The inspectors reviewed system operating procedures, applicable motor-operated valve calculations, system drawings, operator logs, and design basis documents as well as other past issue reports to ensure Exelon took appropriate actions in accordance with the requirements of their corrective action program.

b. Findings and Observations No findings of significance were identified. The inspectors confirmed that the high RHR pump discharge pressure would not adversely affect the operation of the RHR motor operated valves and therefore not affect the safety function of the system. Additionally, the inspectors confirmed that Exelon appropriately categorized and prioritized this issue in their corrective action program.

Enclosure

14

.4 Annual Sample: Unit 1 Core Spray Test Bypass Valve Failed to Close

a. Inspection Scope The inspectors reviewed Limerick's apparent cause evaluation, extent-of-condition, and corrective actions associated with IR 516425 regarding the failure of the Unit 1 CS test bypass primary containment isolation valve (PCIV) to close on August 2, 2006. The inspectors evaluated Exelon's actions against the requirements of the corrective action program and applicable regulatory requirements.

b. Findings and Observations Introduction. The inspectors identified a Green, non-cited violation of 10CFR50, Appendix B, Criterion XVI, "Corrective Action," for not correcting a condition adverse to quality associated with safety-related 480 volt motor operated valves (MOVs) in a timely manner.

Description. On June 4, 2008, Unit 2 RCIC turbine exhaust line vacuum breaker outboard PC IV (HV-049-2F080) failed to close during testing. Exelon determined that the cause of the MOV's failure was mechanical binding due to misalignment between the auxiliary contact switches located in the associated motor control center starter. The contact switch arrangement was "double stacked", meaning two sets of double auxiliary contacts switches (one base switch and one add-on switch) were connected on top of each other. Auxiliary contact switch binding due to misalignment between the base switch and add-on switch caused a normally qlosed set of contacts to stay in the open

\ position. The contact serves as an interlock in the closing circuit for the valve to prevent simultaneous energization of the open and close coil in the control circuit. With the contact stuck in the open position, energization of the close coil was prevented.

The inspectors reviewed the history of MOV failures due to auxiliary contact switch binding. This review included IR 516425 associated with the failure of the Unit 1 CS Loop A test bypass PCIV (HV-052-1F015A) to close on August 3,2006. Exelon also determined this failure to be caused due to binding of the "double stacked" auxiliary contact switches similar to the HV-049-2F080 failure. Exelon's investigation found that the same failure mechanism had also been previously experienced at Peach Bottom Atomic Power Station. The problem associated with binding caused by misalignment of "double stacked" auxiliary contact switches was significantly reduced at Peach Bottom Atomic Power Station by eliminating the add-on double auxiliary contact switch and replacing them with less susceptible single auxiliary contact switches. Unused spare contacts were also eliminated which minimized the need to use more than one single auxiliary contact switch.

Exelon determined that the extent-of-condition of the cause of potential binding included all 480VAC motor starters installed with "double stacked" auxiliary contact switches on Units 1 and 2. For pumps and fans, the normally closed auxiliary contacts were typically used in non-critical indication circuits. However, for MOVs, the normally closed contact is used in the close and open interlock and failure will prevent valve operation. The station's corrective actions included inspecting all high and medium risk valve controllers, as defined by Exelon's Specification NE-145, "Selection of Generic Letter 96-05 Program Valves," to identify susceptible controllers and to develop a plan to eliminate the add-on double auxiliary contact arrangement during the next respective system outage window. No specific actions were identified for valves in low risk applications.

Enclosure

15 The corrective action for low risk valves was to develop a method to fully eliminate the use of this component in low risk applications. This action for low risk valves had a status note following it stating "pending management decision on necessity." The due date for completing the corrective actions was June 30, 2009.

The inspectors compared the corrective actions associated with low risk valves with the guidance in LS-AA-125, "Corrective Action Program Procedure," Revision 11. The inspectors concluded that these actions did not meet the guidance that corrective actions "clearly state the desired end result" or that the corrective actions "address the identified cause."

The performance deficiency associated with this issue is the failure to take appropriate corrective actions in a timely manner to address the adverse condition of mechanical binding in "double stacked" auxiliary contact switches for low risk motor-operated valves.

The performance deficiency applies to both Units 1 and 2 because Exelon's established corrective action in IR 516425 applied to both units. As a result, HV-049-2F080, a low risk safety-related valve, failed to close due to mechanical binding of the "double stacked" auxiliary contact switches on June 4, 2008. This performance deficiency applies to both Units 1 and 2 because Exelon's established corrective actions in IR 516425 applied to both units.

Analysis. The finding was more than minor because it was associated with the structures, systems, and components and barrier containment performance attribute of the Barrier Integrity cornerstone and affected the objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents and events. The inspector assessed the finding using Phase 1 of IMC 0609, Appendix A, "Significance Determination Process for Reactor Inspection Findings for At-Power Situations" and determined the finding to be of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment because the RCIC turbine exhaust line vacuum breaker inboard PCIV was available to be closed.

This finding has a cross-cutting aspect of Problem Identification and Resolution because Exelon did not take appropriate corrective actions to address safety issues and adverse trends in a timely manner, commensurate with the safety significance and complexity, in that, a previously identified deficiency, which disabled a primary containment isolation valve, was not corrected. This resulted in disabling an additional primary containment isolation valve. (P.1 (d))

Enforcement. 10CFR50, Appendix B, Criterion XVI, "Corrective Action," requires, in part, that measures shall be established to assure that conditions adverse to quality are promptly identified and corrected. Contrary to the above, between August 3, 2006 and June 4, 2008, Exelon did not correct a condition adverse to quality associated with safety-related motor operated valve motor control center auxiliary contact switches that was identified by the failure of Unit 1 CS Loop A test bypass PCIV (HV-052-1 F015A) to close on August 3, 2006. Because the condition adverse to quality was not corrected, the Unit 2 RCIC turbine exhaust line vacuum breaker outboard PCIV (HV-049-2F080) did not close on June 4, 2008, due to binding of the auxiliary contact switch in its motor starter circuitry. Because the finding is of very low safety significance and has been entered into Exelon's CAP as IR 781939, this violation is being treated as a Green NCV, consistent with Section VI.A.1 of the NRC Enforcement policy. This inspector-identified Enclosure

16 non-cited violation was entered into Exelon's CAP as IR 781939. (NCV 05000352, 353/2008003-01, Failure to Correct Adverse Condition Associated with Motor Operated Valves.)

40A3 Event Follow-Ug (71153 - 2 samples)

.1 Plant Event Review

a. Inspection Scope For the two plant events listed below, the inspectors observed plant parameters and, as applicable, reviewed personnel performance and evaluated performance of mitigating systems. The inspectors communicated the plant events to appropriate regional personnel and compared the event details with criteria contained in IMC 0309, "Reactive Inspection Decision Basis for Reactors," for consideration of additional reactive inspection activities. The inspectors reviewed Exelon's follow-up actions related to the events to assure that appropriate corrective actions were implemented commensurate with their safety significance.

• IR 766331, Unit 2 A Suppression Pool Cooling Return Valve (HV-051-2F024A)

Discovered to Have a Stem-Disc Separation; and

• Unit 2 Turbine Building Condenser Bay Flooding due to Failure of a Circulating Water Anode on May 22, 2008.

b. Findings I

No findings of Significance were identified .

.2 (Closed) LER 05000352102008-001: Source Range Monitor Inoperable While Control Rod Moved.

On March 16,2008, during the Unit 1 refueling outage, a control rod was withdrawn with the source range monitor in the affected core quadrant inoperable which is contrary to TS 3.9.2, Refueling Operations - Instrumentation. This issue was identified by an Instrumentation and Controls technician performing maintenance activities in the auxiliary instrument room. The root cause of the event was the control room supervisor and reactor operator failing to ensure the "C" source range monitor was not bypassed prior to declaring it operable. The source range monitor was restored to operable and the control rod was inserted. The event is documented in Exelon's corrective action program as IR 750227. The enforcement aspects of this issue are discussed in Section 40A7. This LER is closed .

.3 (Closed) LER 05000352/02008-002: Unit 1 Trip Due to Actuation of Power Load Unbalance.

Oh March 22, 2008, Unit 1 automatically scrammed due to a main turbine trip during power escalation following refueling outage with the unit at 87 percent power. The root cause of the scram was the generator protection relay logic failure caused by an inadequately seated tap screw on the "B" phase of the Accidental Energization (350-G101) relay. The failure caused a false input into the power load unbalance circuit of the electro-hydraulic control system that resulted in a turbine trip and reactor scram.

Enclosure

17 Exelon's investigatioh' could not determine when the tap screw was inadequately seated.

The inspectors determined that there was no performance deficiency associated with this event since the post-maintenance testing performed following the relay's replacement during the Spring 2008 refueling outage was consistent with industry practices. As a result of this event, the main generator relay testing procedures will be revised to include a circuit loop signal verification test to ensure reliability of newly installed equipment.

The event is documented in Exelon's corrective action program as IR 750227. This LER is closed .

.4 (Closed) Licensee Event Report (LER) 05000353/02008-003: Condition Prohibited By Technical Specifications Due To Inoperable Radiation Monitor.

On April 15, 2008, during a review of ST-2-013-600-2, "Reactor Enclosure Cooling Water (RECW) Radiation Monitor Functional Test," the Surveillance Test Coordinator identified the "as-left" value of the HI-HI setpoint was above the required limit of 1050 counts per minute (CPM). The "as-found" value for the HI-HI setpoint was recorded as 1100 CPM as indicated on the radiation monitor analog scale. During the data review, the technician performing the test on March 24, 2008, did not identify that this value was above the required limit. Contrary to TS 3.3.7.1, "Monitoring Instrumentation -

Radiation Monitoring Instrumentation," the station did not collect the required grab samples for the inoperable monitor during the effected period. The condition was caused by a less-than-adequate self-check by the technician recording the data during the functional surveillance test as well as a less-than-adequate supervisory review.

Corrective actions included a workgroup stand-down to reinforce the consequences of not applying the barriers that are designed for error prevention and the addition of independent reviews of surveillance test data. The event was documented in Exelon's corrective action program as IR 763510. The enforcement aspects of this issue are discussed in section 40A7. This LER is closed.

40A6 Meetings. Including Exit Exit Meeting Summary On July 7, 2008, the resident inspectors presented the inspection results to Mr. C. Mudrick and other members of his staff. The inspectors confirmed that proprietary information was not included in the inspection report.

40A7 Licensee-Identified Violations The following violations of very low safety significance (Green) were identified by Exelon and are violations of NRC requirements which met the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for disposition as NCVs.

• Technical Specification 3.3.7.1, "Monitoring Instrumentation - Radiation Monitoring Instrumentation," requires one operable reactor enclosure cooling water (RECW) system radiation monitor channel "at all times." Action 72 of Table 3.3.7.1-1 requires obtaining a grab sample every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> with the required monitor inoperable. Contrary to TS 3.3.7.1, the required RECW Radiation Monitor was inoperable in Unit 2 from March 24, 2008 until April 15, 2008 without obtaining a grab sample every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The event is documented in Exelon's CAP as IR 763510. The finding was of very low safety significance Enclosure

18 because it does not represent an open. pathway in the physical integrity of reactor containment.

• Technical Specification 3.9.2, "Refueling Operations - Instrumentation," requires an operable source range monitor (SRM) in the quadrant where core alterations are being performed when in Operational Condition 5 (OPCON 5). If this requirement is not satisfied, the operators are required to immediately suspend all operations involving core alterations and insert all insertable control rods.

Contrary to TS 3.9.2, on March 16, 2008, with Unit 1 in OPCON 5, a control rod was withdrawn with the required source range monitor in the affected core quadrant inoperable. The event is documented in Exelon's CAP as IR 750227.

The finding is of very low safety significance because the finding did not require quantitative assessment per Checklist 7 of Attachment 1 to IMC 0609, Appendix G, "Shutdown Operations Significance Determination Process."

ATTACHMENT: SUPPLEMENTAL INFORMATION 1

Enclosure

A-1 SUPPLEMENTAL INFORMATION KEY POINTS OF CONTACT Exelon Generation Company C. Mudrick, Site Vice President E. Callan, Plant Manager D. DiCello, Manager, Radiation Protection R. Dickinson, Director, Engineering P. Gardner, Director, Operations R. Kreider, Manager, Regulatory Assurance M. Jesse, Manager, Nuclear Oversight S. Bobyock, Manager, Plant Engineering M. Crim, Manager, Operations Services C. Gray, Manager, Radiological Engineering R. Harding, Engineer, Regulatory Assurance J. Berg, System Manager, HPCI J. George, System Manager, RHR M. Gift, System Manager, Radiation Monitoring Systems L. Lail, System Manager, EDG R. Gosby, Radiation Protection Technician, Instrumentation D. Malinowski, Simulator Instructor J. Sprucinski, Senior Radiation Protection Technician LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened None Closed 05000353/02008-003 LER Condition Prohibited By Technical Specifications Due To Inoperable Radiation Monitor (Section 40A3.4)05000352/02008-001 LER Source Range Monitor Inoperable While Control Rod Moved (Section 40A3.2)05000352/02008-002 LER Unit 1 Trip Due to Actuation of Power Load Unbalance (Section 40A3.3)

Opened and Closed 05000352-05000353/2008003-01 NCV Failure to Correct Adverse Condition Associated with Motor Operated Valves (Section 40A2.4)

Discussed None Attachment

A-2 LIST OF DOCUMENTS REVIEWED Section 1R01: Adverse Weather Protection Procedures E-5, Grid Emergency, Revision 11 Limerick Generating Station Units 1 and 2 Individual Plant Examination for External Events,

• June 1995 OP-AA-108-107, Switchyard Control, Revision 2 OP-AA-1 08-1 07-1001, Station Response to Grid Capacity Conditions, Revision 2 OP-AA-1 08-1 07-1002, I nterface Agreement between Exelon Energy Delivery and Exelon Generation for Switchyard Operations, Revision 4 OP-AA-108-107-101, Station Response to Grid Capacity Conditions, Revision 2 PJM Manual 13, Emergency Operations, Revision 33 PJM Manual 3, Transmission Operations, Revision 30 UFSAR Section 2.4, Hydrologic Engineering UFSAR Section 3.4, Water Level (Flood) Design UFSAR Section 9.5.4, Diesel Generator Fuel Oil System WC-AA-8000, Interface Procedure between Exelon Energy Delivery (COMED/PECO) and Exelon Generation (Nuclear Power) for Construction and Maintenance Activities, Revision 2 Section 1R04: Eguipment Alignment Procedures \

ARC-BOP-OCC101 A1, Control Room Air Supply Filter A DP HI/OA Temperature Trouble, Revision 0 RT-100-370-0, Inspection of Emergency Diesel GeneratorFuel Oil Storage Tank Leak Collection Sumps, Revision 7 ST-4-078-731-0, A CREFAS Charcoal Adsorber/HEPA Filter Test, Revision 4, completed 11/08/2006 ST-4-078-801-0, A CREFAS Charcoal Analysis, Revision 6, completed 12122/2006 ST-6-078-301-0, A CREFAS Monthly Operability Test, Revision 14, completed 04/06/2008 Issue Reports and Action Requests IR 648657, Defective Damper Seal IR 770342, D22 FOST Vault Seals Degraded around Through-Floor Piping IR 770348, D22 FOST-Fuel Oil Fill Line into Vault is Rusted IR 770355, D22 FOST Vault-Conduit Piping is Cracking .

IR 770357, D22 FOST-Fuel Oil Gravity Return Line is Rusted Miscellaneous Limerick Active LCO Logs, dated 04/21/2008 Online Risk Assessment for Work Week 0817 Section 1R05: Fire Protection Procedures F-FOSB-001, Pre-Fire Plan Strategy for Fuel Oil Storage Building, Revision 0 F-P-001, Diesel Driven Fire Pump (Circ Water Pump Structure Elevation 217)," Revision 6 F-S-001 Common "Spray Pond Pump Structure Western Half Fire Area 122," Revision 7 Attachment

A-3 F-S-002 Common, "Spray Pond Pump Structure Eastern Half Fire Area 123," Revision 7 Issue Reports and Action Requests IR 360027, Smoke Detector LED Did Not Illuminate Section 1 ROG: Flood Protection Measures Procedures Special Event Procedure SE-4-1, Reactor Enclosure Flooding, Revision 8 Individual Plant Examination, Limerick Generating Station Units 1 and 2 Updated Final Safety Analysis Report, Chapter 3, Design of Structure, Components, Equipment, and Systems Issue Reports and Action Requests IR 672157, LSH-55140 Failed to Actuate during Preventive Maintenance Work Orders R0046120 Section 1 R11: Licensed Operator Regualification Program Procedures LSTS-3323, Steam Leak Valve Outside Containment, Revision 2 ON-104, Control Rod Problems, Revision 41 T-101, RPV Control, Revision 19 T -102, Primary Containment Control, Revision 22 T-117, Level Power Control, Revision 12 Section 1R12: Maintenance Effectiveness Issue Reports and Action Requests IR 707564, A(1) Determination for Instrument Air System Miscellaneous Maintenance Rule Expert Panel Meeting Minutes dated 12111/2007 Maintenance Rule Scope and Monitoring Report for Instrument Air Maintenance Rule Scope and Monitoring Report for HPCI Maintenance Rule Scope and Monitoring Report for Containment and Leak Testing Maintenance Rule Condition Report Review for IR 671975 Performance Monitoring Summary for Instrument Air System Section 1R13: Maintenance Risk Assessments and Emergent Work Control Issue Reports and Action Requests IR 516425, HV-051-1F015A Failed to Close from Handswitch Miscellaneous Paragon Risk Assessment for April 3D, 2008 Attachment

A-4 Section 1 R15: Operability Procedures RT-6-041-490-1, Suppression Pool Gross Input Leak Rate Determination, Revision 2 RT-6-041-490-1, Suppression Pool Gross Input Leak Rate Determination, Revision 3 RT-6-041-490-1, Suppression Pool Gross Input Leak Rate Determination, Revision 13 Issue Reports and Action Requests IR 665448, Diesel Temperature Switches Found Out of Calibration IR 698972, Perform Review to Improve Heat Exchanger Heat Transfer Test Evaluations IR 709577, Critical Temperature Switch Found in Failed Condition IR 711906, D24 Critical Temperature Switches Deficiency IR 756914, 1C SRV Second Stage Temperature is Reading 2 Degrees Low IR 765062, D13 FOST Mechanical Indicator Stuck IR 780592, Post 'A' Flow Balance 89-13 Margin Review of CS Unit Coolers Work Orders.

M1660252 Miscellaneous LER 05000352/95-008, Inadvertent Opening of 1M Safety Relief Valve LER 05000353/01-001, Inadvertent Opening of 2N Main Steam Relief Valve PEP 10012314, 2N SRV Inadvertently Lifted and Remained Open During SID Section 1R19: Post Maintenance Testing Procedures S55.1.D, HPCI System Full Flow Functional Test, Revision 34 ST-6-055-200-2, HPCI Valve Test, Revision 47, completed 6/17/08 ST-6-055-230-2, HPCI Pump Valve and Flow Test, Revision 60, completed on 6/17/08 Issue Reports and Action Requests IR 786980, Unit 2 HPCI Proactive Adjustment of Stop Valve Balance Chamber Work Orders R0951637 Miscellaneous Online Daily Plan for Work Week 0825 Clearance 08001087 Clearance 08001093 Section 1 R22: Surveillance Testing Procedures ST-6-092-115, D11 Diesel Generator 4KV Safeguards Loss of Power LSF/SAA and Outage Testing, Revision 10 Issue Reports and Action Requests IR 205101, Unexplained Rise in f<YV and KVAR during Diesel Generator Runs IR 291:304, D12 Diesel Generator KVAR Swings during RT-6-902-502-1 Attachment

A-5 IR 578265, KVAR Swings during D12 Cooldown IR 766310, 1 RERS Flow Low Per ST-6-076-250-1 IR 770701, Septoint of FSL-076-294A may Interfere with 2B RERS IR 770857, FSL-076-1948 Requires Setpoint Optimization IR 772343, D12 Diesel Generator Large VAR Change IR 784549, ST-6-076-250-1 Performed without an Eval Comp Measure A 1498892, D12 Diesel Generator A 1618063, D12 Diesel Generator Excitation Miscellaneous 6380E, Diesel Generator Voltage Regulation Study, Revision 3 Diesel Generator Fuel Oil Transfer Pumps In-Service Testing Bases Document ECR LG 02-00839, Revise 1ST Program for DG FD Transfer Pump Exelon 1ST Program Technical Position, Classification of Skid Mounted Components Section EP6: Drill Evaluation Procedures EP-AA-1000, Exelon Nuclear Standardized Radiological Emergency Plan, Revision 19 Issue Reports and Action Requests .

IR 769938, Multiple Failed Drill/Exercise Performance Opportunities during Licensed Operator Requalification Training Section 2PS2: Radioactive Material Processing and Transportation (71122.02)

Procedures M-053-003, 3-55 Transport Cask Handling, Revision 10 M-053-004, 8-120B Transport Cask Operations, Revision 9 RP-AA-600, RADIOACTIVE MateriallWaste Shipments, Revision 10 RP-AA-600-1001, Exclusive Use and Emergency Response Information, Revision 4 RP-AA~600-1 002, Highway Route Controlled Quantity Advance Notification for RadioactivelWaste Shipments, Revision 2 RP-AA-600-1003, Radioactive Waste Shipments to BARNWELL and the DEFENSE CONSOLIDATION FACILITY, Revision 5 RP-AA-600-1004, Radioactive Waste Shipments to ENVIROCARE, Revision 7 RP-AA-600-1005, Radioactive Material and Non-Disposal Site Waste Shipments, Revision 10 RP-AA-600-1006, Notification Requirements for Radioactive Waste Shipments Greater Than Ten Times the Minimum Quantity of Concern, Revision 4 RP-AA-601, Surveying Radioactive Material Shipments, Revision 10 RP-AA-601, Transportation Accident Response, Revision 0 RP-AA-602, Packaging of Radioactive Material Shipments, Revision 12 RP-AA-602-1 001, Packaging of Radioactive MateriallWaste Shipments, Revision 9 RP-AA-603, Inspection and Loading of Radioactive Material Shipments, Revision 3 RP-AA-603-1001, Inspection and Loading of Radioactive MateriallWaste Shipments, Revision 1 RP-AA-605, 10 CFR 61 Program, Revision 0 RP-LG-6050, 10 CFR 61 Waste Stream Sampling and Analysis, Revision 2 RW-226, Radwaste and Radioactive Material Inspection & Loading Operations, Revision 13 RW-AA-100, Process Control Program for Radioactive Wastes, Revision 5 Attachment

A-6 Nuclear Oversight Audits Self-Assessment Report: RadWaste, Transportation, and Process Control Programs Audit No. NOSA-LlM-08-04 (IR 745595), Chemistry, RadWaste, Effluent and Environmental Monitoring Audit Report 2008 Chemistry, Radwaste, Effluent, and Environmental Monitoring Audit Comparative Report Shipping Manifests*

Shipment No.MW-07-014, Irradiation Hardware, Type B Shipment No. MW-07-015, Irradiated Hardware, Type B Shipment No. MW-07-016, Dewatered Mechanical Filters, Type B Shipment No. MW-07-017, Irradiated Hardware, Type B Shipment No. MW-08-024, Green-Is-Clean, Limited Quantity Issue Reports 748754, 765045, 767494, 723737, 748754, 765045, 764510, 769079, 767313, 766508, 766514, 766506, 766499, 764369, 78343 Miscellaneous 10 CFR 61 Reports for 2006,2007, and 2008 2007 Limerick Annual Radioactive Effluent Release Report NHPT2-1100, DOT 79-19 Training Plan for Radiation Protection Personnel NRWSHP 1000, Lesson Plan for DOT 79-19 Training Rad Waste and Radioactive Material Shipping Logs for 2006,2007, and 2008 Radwasterrransportation Training Records for selected personnel TQ-AA-223-F070, DQT 79-19 Training for Support of Radioactive Material Shipping, Revision 3 WMG-07-004-RE-080, Packaging and Disposal of Irradiated Hardware at Limerick Generating Station during 2007 Section 40A1: Performance Indicator (PI) Verification Procedures S92.6.N, Diesel Oil Storage Tank Lineup to Fill Other Than its Associated Day Tank, Revision 10 Issue Reports and Action Requests IR 671925, HV-055-2F093 Failed to Operate from the Hand Switch IR 700312, HPCI LER Retraction Not Communicated to Program Coordinator IR 712015, 2A-P206 Core Spray Pump Mechanical Seal DriveColiar IR 741722, Unit 2 HPCI EGM Output Outage Fluctuation IR 741725, Unit 2 HPCI Erratic Control Valve Position Indication IR 747350, 1R12 LL - D13 Bus Trip Test - "C" ESW Pump Impact Not Planned IR 755999, PSV Failed Seat Tightness Test IR 767479, Relayed Alarm Div 3 RHR or SLC Out of Service Reason Unknown Miscellaneous Core Spray Maintenance Rule Failure Report HPCI Maintenance Rule Failure Report Maintenance Rule Failure Report for System 092 Operator Logs 10/1/2008 through 3/31/2008 Operator Logs dated 10/1/2007 - 03/31/2008 RHR Maintenance Rule Failure Report Attachment

A-7 Safeguard DC Power System Maintenance Rule Failure Report Unit 1 and Unit 2 Heat Removal System Unavailability Reports Unit 1 and Unit 2 Heat Removal System Unreliability Reports Unit 1 and Unit 2 MSPI Derivation Reports for Emergency AC Power System Unit 2 EDG System Unavailability for January 2008 Section 40A2: Identification and Resolution of Problems Procedures ARC-MCR-215 F3, 2B RHR Pump Discharge HilLo Pressure, Revision 1 S51.4.A, Manual Depressurization of RHR, Revision 9 S51.8.A, Suppression Pool Cooling Operation (Start-up and Shutdown) and Level Control, Revision 38 Issue Reports and Action Requests IR 470120, The HV-051-1F017C Possibly Leaking By IR 502283, NRC Issues Concerning 1B RHR Pump Discharge Alarms IR 512162, 2C RHR PP Discharge Piping Rising Pressure IR 567128, Received 2A RHR Pump Discharge High Pressure IR 571708, Received Alarm 2B RHR Pump Discharge HilLo IR 571794, 2A RHR Pump Discharge High Pressure IR 636580, 2A RHR Pump Discharge High Pressure Following Pump Shutdown IR 643538, 2A RHR Pump Discharge HilLo Pressure Alarm IR 643594, 2B RHR Pump Discharge Hi/Lo Pressure Alarm IR 666964, Unexpected MCR 213 F3 IR 755510, 2B RHR Pump Discharge Hi/Lo Pressure (213 F3) Alarm Received Miscellaneous AC Motor Operated Valve Calculation for HV-051-2F024B Calculation LM-50, Residual Heat Removal System MOV DP Calculation, Revision 5 Motor Operated Valve Control Parameters for HV-051-2F024B Operator Logs, dated 04/14/2005 through 04/14/2008 Section 40A3: Event Follow-up Procedures SE-4, Flood, Revision 6 SE-4-2, TurbinelControl Enclosure Flooding, Revision 2 Issue Reports and Action Requests IR 654041, Dual Indication for HV-051-2-F024A during Stoke Close IR 656212, Perform Diagnostic Test as follow-up to Limit Switch Failure Miscellaneous Drawing 2111-3, Revision 3,18 "-300" Globe Valve LGS1 and 21ST Program ML-008, Revision 8 Work Order C0221891, Replace Limit Switches and Diagnostic Testing Attachment

A-8 LIST OF ACRONYMS ADAMS Agencywide Documents Access Management System AC Alternating Current AR action request CAP Corrective Action Program CFR Code of Federal Regulations CNO Chief Nuclear Officer CPM counts per minute CREFAS control room emergency fresh air system CS core spray DEP drill and exercise performance DOT Department of Transportation EDG emergency diesel generator ERO emergency response organization FOST fuel oil storage tank HPCI high pressure coolant injection IMC Inspection Manual Chapter IR issue report LER Licensee Event Report MOV motor operated valves NCV non-cited violation NEI Nuclear Energy Institute NRC Nuclear Regulatory Commission OPCON operational condition P&ID piping and instrumentation drawing \

PARS Publicly Available Records PC IV primary containment isolation valve PCP process control program PI performance indicator PMT post-maintenance test RCIC reactor core isolation cooling RECW reactor enclosure cooling water RERS reactor enclosure recirculation system RHR residual heat removal RRP reactor recirculation pump RTP rated thermal power SOP ,significance determination process SGTS standby gas treatment system SOW system outage window SRM source range monitor SSC structure, system, component ST surveillance test TS technical speCification UFSAR updated final safety analysis report Attachment

UNITED STATES NUCLEAR REGULATORY COMMISSION REGION I 475 ALLENDALE ROAD KING OF PRUSSIA, PA 19406-1415 November 13,2008 Mr. Charles G. Pardee President and Chief Nuclear Officer (CNO)

Exelon Nuclear Chief Nuclear Officer (CNO)

AmerGen Energy Company, LLC 4300 Winfield Rd.

Warrenville, IL 60555

SUBJECT:

LIMERICK GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000352/2008004 AND 05000353/2008004

Dear Mr. Pardee:

\

On September 30, 2008, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your Limerick Generating Station Units 1 and 2. The enclosed integrated inspection report documents the inspection results which were discussed on October 2, 2008, with Mr. C. Mudrick and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

This report documents one NRC-identified finding of very low safety significance (Green).

The finding was determined to involve a violation of an NRC requirement. However, because of the very low safety significance and because it is entered into your corrective action program (CAP), the NRC is treating the finding as a non-cited violation (NCV), consistent with Section VI.A.1. of the NRC Enforcement Policy. If you contest the NCV in this report, you should provide a response within 30 days of the date of this inspection report, with basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administration, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-001; and the NRC Resident Inspector at the Limerick facility.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the Enclosure 10

• C. Pardee 2 NRC's document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html(the Public Electronic Reading Room).

Sincerely, IRA!

Paul G. Krohn, Chief Projects Branch 4 Division of Reactor Projects Docket Nos: 50-352, 50-353 License Nos: NPF-39, NPF-85

Enclosure:

Inspection Report 05000352/2008004 and 05000353/2008004 w/

Attachment:

Supplemental Information cc w/encl:

C. Crane, President and Chief Operating Officer, Exelon Generation M. Pacilio, Chief Operating Officer, Exelon Generation Company, LLC C. Mudrick, Site Vice President - Limerick Generating Station E. Callan, Plant Manager, Limerick Generating Station R. Kreider, Regulatory Assurance Manager R. DeGregorio, Senior Vice President, Mid-Atlantic Operations K. Jury, Vice President, Licensing and Regulatory Affairs P. Cowan, Director, Licensing D. Helker, Licensing B. Fewell, Associate General Counsel Correspondence Control Desk D. Allard, Director, PA Department of Environmental Protection J. Johnsrud, National Energy Committee, Sierra Club Chairman, Board of Supervisors of Limerick Township J. Powers, Director, PA Office of Homeland Security R. French, Director, PA Emergency Management Agency

C. Pardee 3 NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRC's document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html(the Public Electronic Reading Room).

Sincerely, IRA!

• Paul G. Krohn, Chief Projects Branch 4 Division of Reactor Projects Distribution w/encl: (via E-mail)

S. Coilins, RA M. Dapas, DRA D. Lew, DRP J. Clifford, DRP P. Krohn, DRP

. R. Fuhrmeister, DRP T. Setzer, DRP E. DiPaolo, DRP, Senior Resident Inspector N. Sieiler, DRP, Resident Inspector L. Pinkham, Resident OA S. Williams, RI, OEDO P. Bamford, PM, NRR E. Miller, NRR, Backup R. Nelson, NRR H. Chernoff, NRR ROPreportsResource@nrc.gov\

Region I Docket Room (with concurrences)

SUNSI REVIEW COMPLETE: TCS (Reviewer's Initials)

DOCUMENT NAME: G:IDRPIBRANCH4IDraft Inspection Reports for Br 4 for 200813rd Qtr 2008 Draft ReportslLim 3rd Qtr ReportlLlM 2008-004rev3.doc After declaring this document "An Official Agency Record" it will be released to the Pu . .

ML083181209 To receive a copy of this document, indicate in the box: "C" =Copy without attadlmenUenclosure "En =Copy with attachmenVenclosure"~_ _- /

OFFICE RIIDRP I RIIDRP IN RIIDRP I I NAME EDiPaolo/PGK for TSetzerlTCS PKrohn/PGK DATE 11/13/08 11/13/08 11/13/08 OFFICIAL RECORD COpy

1 U.S. NUCLEAR REGULATORY COMMISSION REGION I Docket Nos: 50-352, 50-353 License Nos: NPF-39, NPF-85 Report No: 05000352/2008004 and 05000353/2008004 Licensee: Exelon Generation Company, LLC Facility: Limerick Generating Station, Units 1 & 2 Location: Sanatoga, PA 19464 Dates: July 1, 2008 through September 30, 2008 Inspectors: E. DiPaolo, Senior Resident Inspector C. Bickett, Resident Inspector N. Sieller, Resident Inspector R. Fuhrmeister, Senior Project Engineer J. D'Antonio, Senior Operations Engineer S. Barr, Senior Emergency Preparedness Inspector J. Tifft, Reactor Inspector R. Rolph, Health Physicist G. Meyer, Senior Reactor Inspector M. Gotch, Reactor Inspector Approved by: Paul G. Krohn, Chief Projects Branch 4 Division of Reactor Projects Enclosure

2 TABLE OF CONTENTS

SUMMARY

OF FINDINGS ......................................................................................................... 3 REPORT DETAILS .......................................................................*............................................. 4

1. REACTOR SAFETY ........................................................................................................... 4 1R01 Adverse Weather Protection .................................................................................... 4 1R04 Equipment Alignment .............................................................................................. 4 1R05 Fire Protection ......................................................................................................... 5 1R06 Flood Protection Measures .................................................................................... 6 1R07 Biennial Heat Sink Performance ............................................................................. 8 1R11 Licensed Operator Requalification Program ........................................................... 8 1R12 Maintenance Effectiveness ................................................................................... 10 1R13 Maintenance Risk Assessments and Emergent Work Control .............................. 10 1R15 Operability Evaluations ......................................................................................... 11 1R18 Plant Modifications ............................................................................................... 11 1R19 Post-Maintenance Testing .................................................................................... 12 1R22 SurvEliliance Testing ............................................................................................. 12 1EP4 Emergency Action Level and Emergency Plan Changes ...................................... 13

4. OTHERACTIVITES .......................................................................................................... 13 40A1 Performance Indicator (PI) Verification .......................\ ......................................... 13 40A2 Identification and Resolution of Problems ............................................................. 15 40A3 Event Follow-up ................................................................................................... 17 40A5 Other Activities ..................*................................................................................... 17 40A6 Meetings, Including Exit. ........................................................................................ 17 SUPPLEMENTAL INFORMATION ......................................................................................... A-1 KEY POI NTS OF CONTACT ......................................... ,........................................................ A-1 LIST OF ITEMS OPENED, CLOSED, AND DiSCUSSED ....................................................... A-1 LIST OF DOCUMENTS REVIEWED ...................................................................................... A-2 LIST OF ACRONyMS ..............................................................................................A-7 Enclosure

3

SUMMARY

OF FINDINGS IR 0500035212008004, 05000353/2008004; 07/01/2008 - 09/30/2008; Limerick Generating Station, Units 1 and 2; Flood Protection Measures.

The report covered a three-month period of inspection by resident inspectors and announced inspections by regional reactor inspectors. One NRC-identified Green finding, determined to be a non-cited violation (NCV), was identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process (SOP)." Findings for which the SOP does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight," Revision 4, dated December 2006.

A. NRC-Identified and Self-Revealing Findings Cornerstone: Mitigating Systems

• Green. The inspectors identified a NCV of Technical Specification (TS) 6.8.1, "Administrative Controls - Procedures," because Exelon did not maintain adequate procedures in that Emergency Operating Procedure T-103, "Secondary Containment Control," contained an inappropriate high maximum safe operating flooding level for the Unit 2 High Pressure Coolant Injection (HPCI) room.

The inspectors determined that this finding was greater than minor because it affected the procedure quality attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective of ensuring availability, reliability, and capability of the HPCI system. Emergency Operating Procedure T -103, "Secondary Containment Control," delineated an incorrect vaLue of 40 inches for the Unit 2 HPCI room maximum safe operating (MSO) flooding level. Water at this height in the Unit 2 HPCI room would submerge the auxiliary oil pump and would render the HPCI system inoperable. This finding is of very low safety significance because it did not represent a design or qualification deficiency, a loss of safety system function, an actual loss of safety function of a single train for greater than its TS allowed outage time, or a total loss of any safety function that contributes to external event-initiated core damage sequences. The inspectors determined that this violation has a cross-cutting aspect in the area of problem identification and resolution because Limerick did not perform a thorough extent-of-condition review following a 2005 NCV for a similar issue for the Unit 1 RCIC room MSO level (NCV 05000352/2005003-01).

Although the station identified that the Unit 2 HPCI auxiliary oil pump and its associated junction box were located below the MSO level during the review, Limerick did not thoroughly evaluate the impact of the elevation difference on the operation of the HPCI system (P.1(c)). (Section 1R06)

B. Licensee-Identified Violations None.

Enclosure

4 REPORT DETAILS Summary of Plant Status Unit 1 began the inspection period operating at full rated thermal power (RTP). On September6, 2008, operators reduced power to approximately 80 percent to facilitate main steam isolation and main turbine valve testing, control rod scram time testing, and a control rod

• sequence exchange. Full RTP was achieved on September 7, 2008. Unit 1 operated at full RTP for the remainder of the inspection period.

Unit 2 began the inspection period operating at full RTP. On September 12, 2008, operators reduced power to approximately 60 percent to facilitate main condenser tube leak detection and tube plugging, main steam isolation and main turbine valve testing, control rod scram time testing, and a control rod sequence exchange. Full RTP was achieved on September 15, 2008.

Unit 2 operated at full RTP for the remainder of the inspection period.

1. REACTOR SAFETY Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity 1R01 Adverse Weather Protection Impending Adverse Weather Conditions (71111.01 - 1 sample)

a. Inspection Scope \

The inspectors evaluated implementation of adverse weather preparation procedures and compensatory measures as a result of severe thunderstorms and associated high winds experienced on July 24, 2008. The inspectors toured risk-significant and susceptible plant areas to verify preparation procedures and compensatory measures before the onset of the adverse weather conditions. The inspectors verified that Exelon reviewed emergency response capabilities following the storm. The inspectors reviewed associated issues entered into the corrective action program (CAP) to verify that they were properly characterized for resolution. Documents reviewed are listed in the Attachment.

b. Findings No findings of Significance were identified.

1R04 Equipment Alignment

.1 Partial Walkdown (71111.04Q - 3 samples)

a. Inspection Scope The inspectors performed a partial walkdown of the plant systems listed below to verify the operability of risk significant systems or redundant trains and components when safety-related equipment in the opposite train was either inoperable, undergoing surveillance testing, or potentially degraded. The inspectors used TS's, Exelon operating procedures, plant piping and instrumentation drawings (P&IDs), and the Enclosure

5 Updated Final Safety Analysis Report (UFSAR) as guidance for conducting partial system walkdowns. The inspectors reviewed the alignment of system valves and electrical breakers to ensure proper in-service or standby configurations as described in plant procedures and drawings. During the walkdown, the inspectors evaluated the material condition and general housekeeping of the system and adjacent spaces. The documents reviewed are listed in the Attachment. The inspectors performed walkdowns of the following areas:

• Unit 2 HPCI system;

• 'A', 'S', and 'C' Residual Heat Removal Service Water (RHRSW) pumps when '0' RHRSW pump was out-of-service; and

• Unit 2 RCIC system when Unit 2 HPCI system was out-of-service.

b. Findings No findings of Significance were identified .

.2 Complete System Walkdown (71111.04S - 1 sample)

a. Inspection Scope The inspectors conducted one complete system walkdown of the Unit 1 HPCI system to verify that equipment was properly aligned. The walkdown included reviews of valve positions, major system components, electrical power availability, and equipment deficiencies. The inspectors reviewed system check-off lists, system operating procedures, the system P&IDs, and the UFSAR. The inspectors reviewed outstanding maintenance activities and issue reports (IRs) associated with the Unit 1 HPCI system to determine if they would adversely affect system operability. The inspectors reviewed a sample of IRs dating back to 2003 associated with the system to verify that Exelon evaluated and implemented appropriate corrective actions. The walkdown also included an evaluation of system piping, supports, and component foundations to ensure they were not degraded. The documents reviewed are listed in the Attachment.

b. Findings No findings of significance were identified.

1R05 Fire Protection Fire Protection - Tours (71111.050 - 6 samples)

a. Inspection Scope The inspectors conducted a tour of the six areas listed below to assess the material condition and operational status of fire protection features. The inspectors verified that combustibles and ignition sources were controlled in accordance with Exelon's administrative procedures. Fire detection and suppression equipment was verified to be available for use, and passive fire barriers were verified to be maintained in good material condition. The inspectors also verified that station personnel implemented compensatory measures for out-of-service, degraded, or inoperable fire protection Enclosure

6 equipment in accordance with the station's fire plan. The inspectors toured the following areas:

• Unit 1 'A' Battery Room;

• D11 Switchgear Room;

• Unit 1 Cable Spreading Room;

• Unit 2 Cable Spreading Room;

• Unit 1 Inverter Room; and

• Unit 2 Inverter Room.

a. Findings No findings of significance were identified.

1R06 Flood Protection Measures (71111.06 - 1 sample)

a. Inspection Scope The inspectors reviewed the UFSAR and related flood analysis documents to identify areas that can be affected by internal flooding, to identify features designed to alert operators of a flooding event, and to identify features designed for coping with internal flooding. The inspectors performed a walkdown of the Unit 1 and Unit 2 HPCI rooms.

The inspectors observed flood protection features to assess their ability to minimize the impact of a flooding event. The inspectors performed a review of operator actions contained in off-normal and emergency operating procedures for flooding to verify that

\

they can reasonably be used to achieve desired actions. Documents reviewed are listed in the Attachment.

b. Findings Introduction. The inspectors identified a Green NCV of TS 6.8.1, "Administrative Controls - Procedures," because Exelon did not maintain adequate procedures in that Emergency Operating Procedure T-103, "Secondary Containment Control," Revision 20 contained an inappropriately high maximum safe operating (MSO) flooding level for the Unit 2 HPCI room.

Description. The bases document for Emergency Operating Procedure T-1 03, "Secondary Containment ContrOl," describes the MSO level as "the highest value of a parameter, at which neither (1) equipment necessary for the safe shutdown of the plant will fail, nor (2) personnel access necessary for the safe shutdown of the plant will be precluded." Limerick defined the MSO value for flooding of the Unit 2 HPCI room to be 40 inches above the room floor surface in Emergency Operating Procedure T-103.

Determination of this level was based on a letter from the vendor, dated June 24, 1988, which stated that the limiting component in the Unit 2 HPCI room, with regards to rising water level, would. be a junction box on the HPCI turbine located at a height of 40 inches.

The inspectors performed a walkdown of the Unit 2 HPCI room to verify that there were no components required for operation of HPCI that were located at a height less than the MSO level and discovered that the HPCI auxiliary oil pump and its associated junction box were located below the MSO level. The HPCI auxiliary oil pump provides control oil pressure during system startup for proper functioning of the hydraulic control system to Enclosure

7 open the turbine stop and control valves. Disabling the auxiliary oil pump prior to system startup would render the HPCI system inoperable and not capable of performing its intended safety function. The inspectors concluded that the MSO level was incorrect because operating at this level would render HPCI inoperable due to partial submergence of the auxiliary oil pump motor. The inspectors also determined that Exelon had a previous opportunity to identify this discrepancy in 2005 following an NRC-identified NCV (NCV 05000352/2005003-01) for a similar issue associated with the Unit 1 RCIC room MSO level. As part of the extent of condition review for the 2005 NCV, Exelon evaluated the Unit 2 HPCI room. The review identified that the HPCI auxiliary oil pump and its associated junction box were located below the MSO level.

However, the impact of the elevation difference was not fully evaluated and dispositioned.

This finding is a performance deficiency because Limerick did not designate an appropriate MSO level for the Unit 2 HPCI room in Emergency Operating Procedure T-103, "Secondary Containment Control," Revision 20. The station determined that a new MSO level value of 29 inches would be more appropriate. Limerick implemented a temporary change to T-103 to reflect this new value as an interim measure until the procedure is permanently revised. Additionally, Limerick is planning an extent of condition review on the other Unit 1 and Unit 2 emergency core cooling system rooms.

Exelon documented these items in IR 804992.

Analysis. The inspectors determined that this finding was greater than minor because it affected the procedure quality attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective of ensuring availability, reliability, and capability of the HPCI system. Emergency Operating Procedure T-103, "Secondary Containment Control," delineated an incorrect value of 40 inches for the Unit 2 HPCI room MSO flooding level. Water at this height in the Unit 2 HPCI room would submerge the auxiliary oil pump and would render the HPCI system inoperable. Inspectors evaluated this finding using IMC 0609, Attachment 4, "Initial Screening and Characterization of Findings." This finding is of very low safety significance because it is not a design or qualification deficiency, did not represent a loss of safety system function, did not result in an actual loss of safety function of a single train for greater than its TS allowed outage time, or a total loss of any safety function that contributes to external event-initiated core damage sequences.

The inspectors determined that this violation has a cross-cutting aspect in the area of problem identification and resolution because Limerick did not perform a thorough extent-of-condition review following a 2005 NCV for a similar issue for the Unit 1 RCIC room MSO level (NCV 05000352/2005003-01). Although the station identified that the HPCI auxiliary oil pump and its associated junction box were located below the MSO level during the review, Limerick did not thoroughly evaluate the impact of the elevation difference on the operation of the HPCI system (P.1(c>>.

Enforcement. TS 6.8.1 states, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures as recommended in NRC Regulatory Guide 1.33, Appendix A, February 1978. NRC Regulatory Guide 1.33, Appendix A, Section 6.0, includes procedures for combating emergencies and other significant events, including flooding. Contrary to the above, Emergency Operating Procedure T-103, "Secondary Containment Control," Revision 20 was inadequate in that it delineated an incorrect value for the Unit 2 HPCI room MSO for flooding. Specifically, the value described in T-103 for the Unit 2 HPCI room was 40 inches. Water at this Enclosure

8 height in the Unit 2 HPCI room would submerge the HPCI auxiliary oil pump and would render the HPCI system inoperable. Because this finding is of very low safety significance and Exelon has entered this finding into their corrective action program (IR 804992), this violation is being treated as a non-cited violation consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 05000353/2008004001, Inadequate Secondary Containment Control Procedure) 1R07 Biennial Heat Sin~ Performance (71111.07B - 2 samples)

a. Inspection Scope Based on safety significance and prior inspection history, the inspectors selected the following heat exchangers to evaluate Exelon's means (inspection, cleaning, maintenance, and performance monitoring) of ensuring adequate heat sink performance:

• Unit 2 'A' Residual Heat Removal (RHR) heat exchanger (2AE20S); and

• Unit 2 'D' Emergency diesel generator intercooler heat exchanger (2DES86);

Unit 2 'D' Emergency diesel generator jacket water cooler (2DES07); and Unit 2 'D' Emergency diesel generator lube oil cooler (2DES06).

The inspectors assessed the external condition of the above heat exchangers in the field; reviewed the eddy current, surveillance test, and inspection results; and reviewed the applicable system health reports to confirm that results were acceptable and that design basis assumptions for flow rate, plugged tube percentage, and heat transfer capability had been met. The inspectors discussed cathodic protection, piping corrosion, and heat exchange\- practices, including the specifications and procedures for heat exchanger maintenance, with the Generic Letter 89-13 program engineer, applicable system engineers, and chemistry personnel. The inspectors reviewed applicable corrective action program documents to confirm that identified problems and degraded conditions had been resolved properly. Also, the inspectors inspected equipment conditions in Units 1 and 2 Pipe Tunnel, 2B RHR Room, and 2D Core Spray Room.

The inspectors assessed the condition of the spray pond (ultimate heat sink) and the pump house, and reviewed the 2007 evaluation of spray pond sediment depth. The chemical treatment programs for the spray pond were reviewed to verify that potential bio-fouling mechanisms were being addressed, including ongoing treatment and monitoring. The review included discussions with chemistry personnel and the RHRSW system engineer. The documents reviewed are listed in the Attachment.

b. Findings No findings of significance were identified.

1R11 Licensed Operator Regualification Program (71111.11 - 2 samples)

.1 Quarterly Licensed Operator Regualification Program (71111.11Q - 1 sample)

a. Inspection Scope Enclosure

9 On August 5, 2008, the inspectors evaluated licensed operator requalificatiori simulator scenarios on two operating crews. The scenario tested the operators' ability to respond to engineered safety feature actuations and various failures, including a recirculation pump trip, a loss of coolant accident, and site structure damage. The inspectors observed licensed operator performance including operator critical tasks that measured operator actions required to ensure the safe operation of the reactor and protection of the nuclear fuel and primary containment barriers. The inspectors also assessed group dynamics and supervisory oversight to verify the ability of operators to properly identify and implement appropriate TS actions, regulatory reports, and notifications. The inspectors observed and reviewed the training evaluators' grading and critiques and assessed whether appropriate feedback was provided to the licensed operators. The documents reviewed are listed in the Attachment.

b. Findings No findings of significance were identified .

.2 Limited Licensed Operator Regualification Program (71111.11 B-1 sample)

a. Inspection Scope The requalification program for Senior Reactor Operators Limited to Fuel Handling (LSRO) was evaluated using NUREG 1021, Revision 9, "Operator Licensing Examination Standards for Power Reactors" and Inspection Procedure Attachment 7111111, "Licensed Operator Requalification Program."

. A review was conducted of recent operating history documentation regarding fuel handling found in inspection reports, licensee event reports, the licensee's corrective action program, and the most recent NRC plant issues matrix. The inspectors also reviewed specific events from the licensee's corrective action program to determine if possible training deficiencies existed.

The inspectors evaluated the Limerick 2008 and Peach Bottom 2007 operating tests and the Limerick 2008 and Peach Bottom 2006 written examinations for quality and compliance with the Examiner's Standards. Administration of the five job performance measure operating examinations at Limerick was observed.

On August 12, 2008, the results of the biennial written examination and annual operating tests for 2008 were reviewed to determine whether pass/fail rates were consistent with the guidance of NUREG-1 021, Revision 9, "Operator Licensing Examination Standards for Power Reactors." Performance of all individuals over two years was reviewed to check for adverse trends.

Two years of records for requalification training attendance and license reactivation for all four LSROs were reviewed for compliance with license conditions and NRC regulations. Medical records for three individuals were reviewed.

A sampling of feedback was reviewed and training materials were evaluated for response to this feedback. These materials were also reviewed for incorporation of plant modifications and industry events. The documents reviewed are listed in the Attachment.

Enclosure

10

b. Findings No findings of significance were identified.

1R12 Maintenance Effectiveness (71111.12 - 2 samples)

a. Inspection Scope The inspectors evaluated Exelon's work practices and follow-up corrective actions for structures, systems, and components (SSCs) and identified issues to assess the effectiveness of Exelon's maintenance activities. The inspectors reviewed the performance history of risk significant SSCs and assessed Exelon's extent-of-condition determinations for those issues with potential common cause or generic implications to evaluate the adequacy of the station's corrective actions. The inspectors assessed Exelon's problem identification and resolution actions for these issues to evaluate whether Exelon had appropriately monitored, evaluated, and dispositioned the issues in accordance with Exelon procedures and the requirements of 10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance." In addition, the inspectors reviewed selected SSC classifications, performance criteria and goals, and Exelon's corrective actions that were taken or planned, to evaluate whether the actions were reasonable and appropriate. The documents reviewed are listed in the Attachment. The inspectors performed the following samples:

• IR 516425, "Unit 1 Core Spray Test Bypass Valve Failed to Close;" and

• IR 798687, "Emergency Diesel Generator (EDG) 014 Unresponsive to Main Control Room Controls Coincident with Voltage Swings."

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b. Findings No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13 - 4 samples)

a. Inspection Scope The inspectors evaluated the effectiveness of Exelon's maintenance risk assessments required by 10 CFR 50.65(a)(4). This inspection included discussion with control room operators and risk analysis personnel regarding the use of Exelon's on-line risk monitoring software. The inspectors reviewed equipment tracking documentation, daily work schedules, and performed plant tours to gain assurance that the actual plant configuration matched the assessed configuration. Additionally, the inspectors verified that Exelon's risk management actions, for both planned and emergent work, were consistent with those described in Exelon procedure, ER-AA-600-1042, "On-Line Risk Management." The documents reviewed are listed in the Attachment. Inspectors reviewed the following samples:

• C0225355, *"Installation of Gag on Unit 2 'A' Recirculation Pump Motor-Generator Controls;"

• IR 798188, "B.5.b Pump Run;"

• IR 798687, "EDG 014 Load and Voltage Transient During a 24-hour Endurance Run on July 21, 2008;" and

• IR 808608, "Unit 2 Online Risk with '0' Emergency Service Water (ESW), 'B' RHR, and '0' RHRSW Pumps Out-of-Service."

Enclosure

11

b. Findings No findings of significance were identified.

1R15 Operability Evaluations (71111.15 - 7 samples)

a. Inspection Scope For the seven operability evaluations described below, the inspectors assessed the technical adequacy of the evaluations to ensure that Exelon properly justified TS operability and verified that the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors reviewed the UFSAR to verify that the system or component remained available to perform its intended safety function. In addition, the inspectors reviewed compensatory measures implemented to ensure that the measures worked and were adequately controlled. The inspectors also reviewed a sample of issue reports to verify that Exelon identified and corrected deficiencies associated with operability evaluations. The inspectors performed the following evaluations:

• IR 794500, "Ultrasonic Test Results for RHRSW Piping in Manhole 212;"

• IR 792556, Wiring Discrepancy Identified on Unit 2 'D' Core Spray PUmP Suction Primary Containment Isolation Valve (HV-052-2FOO1D) Controller;"

• IR 798687, "EDG D14 Voltage and Load Transient During Testing on July 21,2008;"

• IR 800086, "Control Room Fresh Air Supply System Operability with Compensatory Measure to Start 'B' Supply Fan With Dedicated Operator;"

• IR 799896, "Flat Washers on Safeguard Systems Blowout Panel (secondary containment);"

• IR 808608, "D ESW Instrument Tap Piping Leak;" and

• IR 772343, "EDG D12 Voltage Swings with EDG Paralleled to Offsite Power Source."

b. Findings No findings of Significance were identified.

1R18 Plant Modifications (71111.18 - 2 samples)

.1 Temporarv Modifications

a. Inspection Scope The inspectors reviewed a temporary plant modification documented in Temporary Change 08-00231, "RHRSW Compensatory Actions for Minimum Wall Condition in Manhole 212." This modification changed the normal operating configuration of system components. The inspectors reviewed the change to ensure that it did not adversely affect systems important to safety. The inspectors compared the temporary change with the UFSAR and TS's to verify that the modification did not affect system operability or availability. The inspectors ensured that station personnel implemented the modification in accordance with the applicable temporary configuration change process. The inspectors also reviewed the impact on existing procedures to verify Exelon made appropriate revisions to reflect the temporary configuration change. The documents reviewed are listed in the Attachment.

Enclosure

12

b. Findings No findings of significance were identified .

.2 Permanent Modifications

a. Inspection Scope The inspectors reviewed a permanent plant modification documented in Engineering Change LG 04-00185, "AVCO Scram Solenoid Pilot Valve Upgrade." The inspectors verified that the modification met the design bases and design assumptions, and that the modification preparation, staging, and implementation did not impair emergency or abnormal operating procedure actions and key safety functions. The inspectors also reviewed the modification to verify that the post-modification testing would establish operability, that unintended system interactions would not occur, and that testing demonstrated that the modification acceptance criteria were met. The documents reviewed are listed in the Attachment.

b. Findings No findings of significance were identified.

1R 19 Post-Maintenance Testing (71111.19 - 5 samples)

a. Inspection Scope The inspectors reviewed the five post-maintenance tests (PMTs) listed below to verify \

that procedures and test activities ensured system operability and functional capability.

The inspectors reviewed Exelon's test procedures to verify that the procedures adequately tested the safety functions that may have been affected by the maintenance activity, and that the acceptance criteria in the procedures were consistent with information in the licensing and design basis documents. The inspectors also witnessed the test or reviewed test data to verify that the results adequately demonstrated restoration of the affected safety functions. The documents reviewed are listed in the Attachment. The inspectors performed the following samples;

• C0225781, "Troubleshoot and Repair EDG D14 Following Voltage and Load Surges During Testing;"

• C0225896, "Rework Control Room Supply Fan Flow Switch, FSL-078-029B;"

• C0226039, "D ESW Pump Discharge Instrument Line Through Wall Leak Repair;"

• R0947845, "Perform Calibration of 20 Regulating Transformer Automatic Controls;"

and

• C0226215, "Unit 1A Reactor Enclosure Recirculation System Inoperable Due to System Dampers CYCling."

b. Findings No findings of Significance were identified.

1R22 Surveillance Testing (71111.22 - 7 samples)

a. Inspection Scope Enclosure

13 The inspectors witnessed the performance and reviewed test data for seven surveillance tests (STs) that are associated with risk-significant SSCs. The review verified that Exelon personnel followed TS requirements and that acceptance criteria were appropriate. The inspectors also verified that the station established proper test conditions, as specified in the procedures, that no equipment preconditioning activities occurred, and that acceptance criteria had been met. The documents reviewed are listed in the Attachment. The inspectors reviewed STs for the following systems and components:

• ST-6-092-313-1, "EDG 013 (slow start) Test;"

• ST-6-098-230-2, "2B Standby Liquid Control Pump, Valve and Flow Test;"

• ST-6-012-231-0, "A Loop RHRSW Pump, Valve and Flow Test;"

• ST-6-092-365-0, "Inoperable Unit 1 Safeguard Power Supply Actions for Both Units;"

• ST-6-051-233-1, "C RHR Pump, Valve and Flow Test;"

• ST-6-020-814-2, "EDG 024 Diesel Fuel Oil Analysis;" and

• ST-6-092-312-2, "EDG 022 Diesel Generator Slow Start Operability Test Run."

b. Findings No findings of significance were identified.

Cornerstone: Emergency Preparedness 1EP4 Emergency Action Level and Emergency Plan Changes (71114.04 -1 Sample)

a. Inspection Scope Prior to this inspection, the NRC had received and acknowledged changes made to the Limerick Generating Station Emergency Plan and its implementing procedures. Exelon developed these changes in accordance with 10 CFR 50.54(q), and determined that the changes did not result in a decrease in effectiveness of the Emergency Plan. The licensee also determined that the Emergency Plan continued to meet the requirements of 10 CFR 50.47(b) and Appendix E to 10 CFR 50. During this inspection, the inspectors conducted a review of Exelon's 10 CFR 50.54(q) screenings for all the changes made to the Emergency Action Level (EAL) Plan, and all of the changes made to the Emergency Plan from August 2007 through July 2008 that could have potentially resulted in a decrease in effectiveness of the Emergency Plan. The inspection was conducted in accordance with NRC Inspection Procedure 71114, Attachment 4. The requirements in 10 CFR 50.54(q) were used as reference criteria. The documents reviewed are listed in the Attachment.

b. Findings No findings of significance were identified.

4. OTHER ACTIVITES 40A1 Performance Indicator (PI) Verification (71151- 9 samples)

.1 Mitigating System and Initiating Events Performance Indicators

a. Inspection Scope Enclosure

14 The inspectors sampled Exelon's submittal of the initiating events and mitigating systems performance indicators listed below to verify the accuracy of the data recorded from the fourth quarter of 2007 through the first quarter of 2008. The inspectors utilized performance indicator definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, "Regulatory Assessment Performance Indicator Guidelines," Revision 5, to verify the basis in reporting for each data element. The inspectors reviewed various

• documents, including portions of the main control room logs, issue reports, power history curves, work orders, and system derivation reports. The inspectors also discussed the method for compiling and reporting performance indicators with cognizant engineering personnel and compared graphical representations from the most recent performance indicator (PI) report to the raw data to verify that the report correctly reflected the data.

The documents reviewed are listed in the Attachment.

Cornerstone: Mitigating Systems (2 samples)

• Units 1 and 2 RHR Mitigating Systems Performance Index.

Cornerstone: Initiating Events (4 samples)

• Units 1 and 2 Unplanned Scrams per 7000 Critical Hours; and

• Units 1 and 2 Unplanned Scrams with Complications.

b. Findings 1 No findings of significance were identified.

.2 Emergency Preparedness rEP) Performance Indicators (3 samples)

a. Inspection Scope The inspectors reviewed data for the Limerick EP Pis, which included: Drill and Exercise Performance (DEP); Emergency Response Organization (ERO) Drill Participation; and Alert and Notification System (ANS) Reliability. The inspectors reviewed the PI data, its supporting documentation, and the information Exelon reported for the third and fourth quarters of 2007, and the first and second quarters of 2008, to verify the accuracy of the reported data. The review of these Pis was conducted in accordance with NRC Inspection Procedure 71151. The acceptance criteria used for the review were 10 CFR 50.9 and NEI 99-02, Revision 5, "Regulatory Assessment Performance Indicator Guidelines."

Additionally, the inspectors performed NRC Temporary Instruction (TI) 2515/175, "Emergency Response Organization, Drill/Exercise Performance Indicator Program Review," which ensured the completeness of the licensee's completed Attachment 1 from the TI, and forwarded that data to NRC Headquarters. The documents reviewed are listed in the Attachment.

b. Findings No findings of significance were identified.

Enclosure

15 40A2 Identification and Resolution of Problems (71152 - 3 samples)

.1 Review of Items Entered into the Corrective Action Program

a. Inspection Scope As required by Inspection Procedure 71152, "Identification and Resolution of Problems,"

and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors screened all items entered into Limerick's corrective action program. The inspectors accomplished this by reviewing each new condition report, attending management review committee meetings, and accessing Exelon's computerized database .

.2 Annual Sample - Load Tap Changer Timing

a. Inspection Scope The inspectors reviewed Exelon's evaluation and corrective actions associated with load tap changer timing verification. The inspectors reviewed condition reports and the associated actions against the requirements of Exelon's corrective action program to ensure that the full extent of the issues were identified, appropriate evaluations were performed, and appropriate corrective actions were specified and prioritized. The inspectors interviewed relevant station personnel and reviewed applicable station procedures to ensure that the issues were addressed appropriately. The documents reviewed are listed in the Attachment.

b. Findings and Observations No findings of significance were identified.

The inspectors determined that Exelon's proposed corrective actions were reasonable with respect to the load tap changer timing issue. Exelon performed an appropriate extent-of-condition review and implemented calculation updates that reflected the current plant configuration. Exelon has scheduled tests to verify the mechanical times for each tap changer in order to validate the voltage calculation study. The inspectors determined that Exelon's conclusion was appropriate. Namely, that although sufficient voltage may exist, there is little margin. Exelon entered this condition into the station margin management program for future action .

.3 Annual Sample - RHRSW Corrosion Issues

a. Inspection Scope The inspectors reviewed implementation of the licensee's corrective action program as it related to ESW and RHRSW pipe wall thinning. The inspectors reviewed corrective action program IRs, work orders, and associated documents. The inspectors reviewed the problem identification documentation including the evaluations of operability and reportability for accuracy and completeness. The inspectors reviewed the extent-of-condition determinations and common cause evaluations. The inspectors reviewed the classification and prioritization of the resolutions to correct the problem. The inspectors interviewed engineering personnel and toured the RHR rooms in Units 1 and 2 to observe the replacement of carbon steel piping with stainless steel piping. The Enclosure

16 inspectors noted that more testing, evaluation, and corrective actions are scheduled for the near term. The documents reviewed are listed in the Attachment.

b. Findings and Observations No findings of significance were identified.

The inspectors tletermined that Exelon's proposed corrective actions were reasonable with respect to the pipe wall thinning issue. Exelon contracted with a vendor to perform an appropriate extent-of-condition and to develop a flaw handbook. Exelon has scheduled tests to verify the condition of buried RHRSW piping using Guided Wave Examination (G-scan) methods. The inspectors observed that one due date out ofthirty (30) was changed without fully assessing the impact to other corrective actions. The due date was for an action to develop contingencies to address the results of the Guided Wave Examinations. Exelon agreed to re-evaluate and assign a due date more

• representative of the overall corrective action schedule .

.4 Operator Workarounds

a. Inspection Scope The inspectors performed an in-depth annual review of plant operator workarounds as documented in Exelon's operator workaround program and corrective action documents.

This review was performed to verify that the licensee identified operator workarounds at an appropriate threshold, entered the issues into the CAP, and planned or implemented appropriate corrective actions. The documents reviewed are listed in the Attachment.

The inspectors reviewed the actions taken to verify that the licensee had adequately addressed the following attributes:

• Complete, accurate, and timely identification of the problem;

• Evaluation and disposition of operability and reportability issues;

• Consideration of previous failures, extent-of-condition, generic or common cause implications;

• Prioritization and resolution of the issue commensurate with the safety significance;

• Identification of the root cause and contributing causes of the problem; and

• Identification and implementation of corrective actions commensurate with the safety significance of the issue.

b. Findings and Observations No findings of significance were identified. The inspectors determined that the issues reviewed did not adversely affect the capability of the operators to implement abnormal or emergency operating procedures and had been appropriately classified and prioritized.

the inspectors performed routine screening of issues entered into Limerick's CAP. The review was accomplished by selectively reviewing copies of Issue Reports (IRs) and accessing Limerick's computerized database.

Enclosure

17 40A3 Event Follow-up (71153 - 1 sample)

a. Inspection Scope The inspectors observed plant parameters and evaluated performance of mitigating systems when a section of RHRSW loop 'A' return piping indicated below American Society of Mechanical Engineers (ASME) minimum wall thickness measurements. The inspectors communicated the event to appropriate regional personnel and compared the event details with criteria contained in IMC 0309, "Reactive Inspection Decision Basis for Reactors," for consideration of additional reactive inspection activities. The inspectors reviewed Exelon's follow-up actions related to the event to assure that appropriate corrective actions were implemented commensurate with their safety significance.

b. Findings No findings of significance were identified.

40A5 Other Activities Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope During the inspection period the inspectors conducted observations of security force personnel and activities to ensure that the activities were consistent with licensee security procedures and regulatory requirements relating to nuclear plant security.

These observations took place during both normal and off-normal plant working hours.

These quarterly resident inspector observations of security force personnel and activities did not constitute any additional inspection samples. Rather, they were considered an integral part of the inspectors' normal plant status review and inspection activities.

b. Findings No findings of significance were identified.

40A6 Meetings. Including Exit Exit Meeting Summarv On October 2, 2008, the resident inspectors presented the inspection results to Mr. C. Mudrick and other members of his staff. The inspectors confirmed that proprietary information was not included in the inspection report.

ATTACHMENT: SUPPLEMENTAL INFORMATION Enclosure

A-1 SUPPLEMENTAL INFORMATION KEY POINTS OF CONTACT Exelon Generation Company C. Mudrick, Site Vice President E. Callan, Plant Manager

• D. DiCello, Manager, Radiation Protection R. Dickinson, Director, Engineering P. Gardner, Director, Operations R. Kreider, Manager, Regulatory Assurance M. Jesse, Manager, Nuclear Oversight S. Bobyock, Manager, Plant Engineering M. Crim, Manager, Operations Services C. Gray, Manager, Radiological Engineering R. Harding, Engineer, Regulatory Assurance J. Berg, System Manager, HPCI J. George, System Manager, RHR M. Gift, System Manager, Radiation Monitoring Systems L. Lail, System Manager, EDG R. Gosby, Radiation Protection Technician, Instrumentation D. Malinowski, Simulator Instructor J. Sprucinski, Senior Radiation Protection Technician

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LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened None Closed 2515/175 TI Emergency Response Organization, Drill/Exercise Performance Indicator, Program Review (Section 40A 1.2)

Opened and Closed 05000353/2008004-01 NCV Inadequate Secondary Containment Control Procedure (Section 1R06)

Discussed None Attachment

A-2 LIST OF DOCUMENTS REVIEWED Section 1 R01: Adverse Weather Protection Procedures OP-AA-1 08-111-1 001, Severe Weather and Natural Disaster Guidelines, Revision 3 SE-9, Preparation for Severe Weather, Revision 26 Issue Reports and Action Requests IR 799853, Security Canopy Moved During High Winds Section 1R04: Equipment Alignment Procedures Design Basis Document L-T-109, Internal Hazards, Revision 5 Design Basis Document L-S-03, High Pressure Coolant Injection, Revision 19 Issue Reports and Action Requests HPCI System IRs 2003-2008 Miscellaneous List of Non-recurring Work Orders for HPCI System HPCI System Health Report, March 2008 Section 1 R06: Flood Protection Measures Procedures T-103 Bases, Secondary Containment Control, Revision 20 BLP 41454, Modification No. 5566, Reactor Enclosure Elevation 177'-0" Flood Levels BLP 44164, Unit 2 Reactor Enclosure Elevation 177'-0" and 217'-0" Flood Levels ARC-MCR-217 A5, HPCI Pump Room Flood, Revision 1 SE-4, Flood, Revision 6 SE-4-1, Reactor Enclosure Flooding, Revision B Issue Reports and Action Requests AR 1610225, Document Walkdown Findings for HPCI Room Flooding Section 1 R07: Biennial Heat Sink Performance Procedures ER-AA-340, GL 89-13 Program Implementing Procedure, Revision 4 ER-AA-340-1001, GL 89-13 Program Implementation Instructional Guide, Revision 6 ER-AA-5400, Buried Pipe and Raw Water Corrosion Program Guide, Rev, 1 ER-AA-5400-1 001, Raw Water Corrosion Program Guide, Revision 0 ER-AA-5400-1002, Buried Piping Examination Guide, Revision 1 Limerick GL 89-13 Program Basis Document, Revision 0 CY-LG-120-828, Clam Control Activities, Revision 5 CY-LG-120-1102, Outside Chemistry/NPDES related Sampling and Analysis Schedule, Revision 18 CY-LG-120-1117, Spray Pond Chemistry Guide, Revision 2 ST-2-011-390-0, ESW/Diesel Generator Heat Transfer Test, Revision 4 Attachment

A-3 M-011-001, LGS Preventive Maintenance Procedure for Diesel Generator Heat Exchanger Cleaning and Examination, Rev 12 Standing work order R0920468-01, EDG heat exchangers Drawings SIM-M-12, Emergency Service Waterl RHR Service Water Overview, Revision 9 8031-M-11, Sh.1-5, Emergency Service Water, Revision 68, 81, 53, 50,48, respectively

• 8031-M-12, Sh. 1-2, Residual Heat Removal Service Water, Revision 62,6, respectively 8031-E-1045, Cathodic Protection Plan - Spray Pond & Cooling Towers Area, Revision 14 8031-E-1046, Cathodic Protection Plan - PCMU, RHR & ESW Piping, Units 1 & 2, Revision 14 Unit 2 RHR Heat Exchanger Assembly & Cross Section Drawings, April 1972 Condition & Action Reports 654500,654548,683817,698972,718198,742927, 780592, 798818,807193,807322,816251, 816784,824496,825137,A899130 Inspections and Evaluations Health Reports for Limerick GL 89-13 Program, First Quarter 2007 to Second Quarter 2008 System Health Reports for ESW, First Quarter 2007 to Second Quarter 2008 System Health Reports for RHRSW, First Quarter 2007 to Second Quarter 2008 Focused Area Self-Assessment, 2008 NRC Heat Sink Inspection Preparation, August 13, 2008 Spray Pond Sediment Map, November 13, 2007 Spray Pond Chemistry Results for October 2007 to September 2008 Spray Pond Inspection Report, November 13, 2007 Zebra Mussel & Asiatic Clam Survey, November 6, 2007

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ECT Test Report for Heat Exchanger 2A-E205, March 2005 WO R0966553, Clean and Eddy Current Test 2A-E205, performed May 19, 2005 IC-C-11-02021, Testing of Cathodic Protection System, performed September 4, 2007 RT-1-012-390-0, RHR Heat Exchanger Heat Transfer Performance Computation Test, performed Feb. 15, 2005 RT-2-011-251-0, ESW Loop A Flow Balance, Revision 15, performed April 26, 2008 RT-6-012-390-2, 2A-E205 Heat Exchanger Heat Transfer Test, performed Feb. 9, 2005 RT-6-109-001-0, Cathodic Protection Monthly Inspection, performed September 4, 2007 ST-1-012-901-0, Spray Pond Structural Inspection, performed September 5,2002, August 10, 2003, August 10, 2005, and July 27,2007 ST-6-011-231-0, A Loop ESW Pump, Valve, and Flow Test, performed May 9, 2008, and August 8, 2008 ST-6-012-232-0, A Loop RHRSW Pump, Valve, and Flow Test, performed May 16, 2008, and August 7, 2008 Structural Integrity Associates, Inc., Limerick ESW/RHRSW Pre-Outage Support, May 7, 2008 Nuclear Event Report NC-07-044, Essential Service Water Piping Degradation, Revision 0 & 1 Operational Event Review - Degradation of Essential Service Water Piping, January 15, 2008 Technical Evaluation - Cumulative Leakage from the ESW System (CR 714581-02)

Technical Evaluation - EDG Permissible Fouling Factors as a Function of ESW Flow and Plugged Tubes (IR 691841)

Apparent Cause Evaluation -Internal Corrosion of RHRSW System Piping (CR 731389)

Apparent Cause Evaluation -Increased Frequency of ESW Throttle Valve Silting (11/14/05)

Apparent Cause Evaluation - Diesel Heat Exchanger GL 89-13 Heat Transfer Test Performed Too Soon After Cleaning (CR 174574)

RHRSW Pipe Minimum Wall Thickness Action Plan (IR 693495-32) 1D-G501, EDG Heat Exchanger Inspection Report, June 23, 2008 Attachment

2D-G501, EDG Heat Exchanger Inspection Report, December 10, 2007 LG 96-02349-000, Undersized Lube Oil Cooler LG 01-01096-000, LGS Unit 1 & 2 GL 98-13 Program Recommendation-Heat Exchanger Cleaning LG 01-00968-000, Final Report on DG Heat Exchanger Performance Tests GL 89-13 Calculation LM-0225, Performance Curve for EDG Heat Exchanger for GL 89-13 Engineering Analysis LEAM-0007, Emergency Diesel Heat Exchanger Performance Tests GL 89-13, September 10,2001.

Evaluation of D-22 EDG Heat Exchanger Performance Test of August 26, 2003 Evaluation of D-22 EDG Heat Exchanger Performance Test of July 24,2004 Evaluation of lube oil cooler fouling factor increases in winter, October 1, 2008 Commitment Change Evaluation 2006-002 ECR LG 96-02349, Undersized Lube Oil Cooler ECR LG 01-01096, GL 98-13 Program Recommendation - Heat Exchanger Cleaning ECR LG 01-00968, Final Report on DG Heat Exchanger Performance Tests GL 89-13 ECR LG 04-00433, Licensing Basis of RHRSW Flow Summary of RHRSW/ESW Valve Pit Inspections Section 1R11: Licensed Operator Regualification Program Procedures LSTS-2052, Limerick Generating Station Training Scenario, Revision 000 Section 1R12: Maintenance Effectiveness Procedures ER-AA-31-1004, Maintenance Rule, Performance Monitoring, Revision 7 ER-AA-310-1004, Functional Failure Cause Determination Evaluation, Revision 5 Issue Reports and Action Requests IR 786390, Re-evaluate IR 516425 for MPFF Section 1R13: Maintenance Risk Assessments and Emergent Work Control Procedures C0225355 Paragon Risk Profile for 07/01/2008 Section 1R18: Plant Modifications Procedures A-1665750, External Corrosion of RHRSW Piping in MH212 ECR LG 08-00231, External Corrosion of RHRSW Piping in MH212 Issue Reports and Action Requests IR 794500, UT Results for MH212 on RHRSW IR 796109, UT Data Results Affected by Surface Condition of Pipe Section 1R19: Post Maintenance Testing Procedures Attachment

A-5 IC-11-00340, Calibration of Fluid Components Single Switch Plant Flow Switches ST-6-092-934-1, D14 Diesel Generator Governor and Voltage Regulator Post Maintenance Testing Issue Reports and Action Requests IR 816856, Prompt Investigation of Unit 1A Reactor Enclosure Recirculation System I noperability Section 1R22: Surveillance Testing Procedures ST-6-012-231-0, 'A' Loop RHRSW Pump, Valve and Flow Test, Revision 55, Completed 6/25/2008 Issue Reports and Action Requests IR 798818, 'C' RHRSW Pump TDH in Alert Range during ST-6-012-231-0 IR 718918, 'A' RHRSW Pump TDH in alert Range during ST-6-012-230-0 IR 808401, OA RHRSW Pump in Alert Range for TDH IR 807742, 1C RHR Pump In Alert Range Section 1EP4: Emergency Action Level lEAL) and Emergency Plan Changes Procedures Limerick Generating Station Emergency Plan Annex (ReVision 14)

LS-AA-104, Exelon 50.59 Review Process (Revision 5)

LS-AA-104-1000, Exelon 10CFR50.59 Resource Manual (Revision4)

EP-AA-120, Emergency Plan Administration (Revision 9)

EP-AA-120-1001, 10CFR50.54(q) Change Evaluation (Revision 5) 10CFR50.54(q) screenings and reviews, dated between August 2007 and July 2008 Section 40A1: Performance Indicator (PI) Verification Procedures LS-AA-2001, Collecting and Reporting of NRC Performance Indicator Data (Revision 11)

LS-AA-2110, Monthly Data Elements for NRC Emergency Response Organization (ERO) Drill Participation (Revision 6)

LS-AA-2120, Monthly Data Elements for NRC Drill/Exercise Performance (Revision 4)

LS-AA-2130, Monthly Data Elements for NRC Alert and Notification System (ANS) Reliability (Revision 5)

DEP PI data, July 2007 - June 2008 ERO Drill Participation PI data, July 2007 - June 2008 Public Notification System PI data, July 2007 - June 2008 NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5 Issue Reports and Action Requests IR 753306, Unit 1 Turbine Trip Reactor Scram IR 754166, Relay 350-G101 '8' Phase Failed IR 730021, Automatic Unit 2 Reactor Scram at 0445 on 02/01/2008 IR 753286, GP-18 Issue Tracking IR 730116, Control Rod 46-47 Did Not Initially Show Full-in Attachment

A-6 Miscellaneous MSPI Derivation Reports for Unit 1 RHR System MSPI Derivation Reports for Unit 2 RHR System Operator Logs, dated 10/2007 - 06/2008 Unavailability Data for Unit 1 and Unit 2 RHR Systems Section 40A2: Identification and Resolution of Problems Procedures ER-AA-5400, Buried Piping and Raw Water Corrosion Program(BPRWCP) Guide, Revision 0 ER-AA-5400-1002, Buried Piping Examination Guide, Revision 0 HU-AA-1212, Technical Task Risk/Rigor Assessment, Pre-Job Brief, Independent Third Party Review, and Post-Job Debrief, Revision 2 LS-AA-125, Corrective Action Program (CAP) Procedure, Revision 11 LS-AA-125-1003, Apparent Cause Evaluation Manual, Revision 7 ER-AA-2007, Evaluating Margins, Revision 1 LS-AA-125, Corrective Action Program Procedure, Revision 10 Issue Reports and Action Requests IR 673843, IR688135, IR694845, IR 695408 A1524780,A1508621,A1645805,A1645806,A1645807,A1645814 Calculations 6300E.20, Voltage Regulation Study, Revision 11 B EE-11-LGS, Automatic Voltage Control Settings for the #10 Station Auxiliary, #20 Regulating, and #101 and #201 Safeguard Transformers, Revision 7 Condition Reports IR-117920, IR-356438, IR-716872, IR-731389 Miscellaneous Main Control Room Deficiency List OP-A-A-102-103, Operator Work-Around Program, Revision 2 OTDM Decision Detail for IR 758788 Attachment

A-7 LIST OF ACRONYMS ADAMS Agencywide Documents Access Management System ANS alert and notification system AR action request ASME American Society of Mechanical Engineers CAP Corrective Action Program CFR Code of Federal Regulations CNO . Chief Nuclear Officer DEP drill and exercise performance EAL emergency action level EDG emergency diesel generator ERO emergency response organization ESW emergency service water HPCI high pressure coolant injection IMC Inspection Manual Chapter IR issue report JPM job performance measure LER Licensee Event Report LSRO limited senior reactor operator MSO maximum safe operating NCV non-cited violation NEI Nuclear Energy Institute NRC Nuclear Regulatory Commission P&ID piping and instrumentation drawing PARS Publicly Available Records PI performance indicator PIM plant issues matrix PMT post-maintenance test RCIC reactor core isolation cooling RHR residual heat removal RHRSW residual heat removal service water RTP rated thermal power SOP significance determination process SSC structure, system, component ST surveillance test TI temporary instruction TS technical specification UFSAR updated final safety analysis report Attachment

UNITED STATES NUCLEAR REGULATORY COMMISSION REGION I 475 ALLENDALE ROAD KING OF PRUSSIA, PA 19406-1415 JallJ.1ary 30, 2009 Mr. Charles G. Pardee Senior Vice President, Exelon Generation Company, LLC President and Chief Nuclear Officer, Exelon Nuclear 4300 Winfield Rd.

Warrenville, IL 60555

SUBJECT:

LIMERICK GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000352/2008005 AND 05000353/2008005

Dear Mr. Pardee:

On December 31,2008, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your Limerick Generating Station Units 1 and 2. The enclosed integrated inspection report documents the inspection results which were discussed on January 9, 2009, with Mr. C. Mudrick and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

This report documents one NRC-identified finding of very low safety significance (Green). The finding was determined to involve a violation of NRC requirements. However, because of the very low safety significance and because it is entered into your corrective action program (CAP),

the NRC is treating the finding as a non-cited violation (NCV), consistent with Section VI.A.1. of the NRC Enforcement Policy. If you contest the NCV in this report, you should provide a response within 30 days of the date of this inspection report, with basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administration, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-001; and the NRC Resident Inspector at the Limerick facility.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the Enclosure 11

NRC's document system (ADAMS). ADAMS is accessible from 'the NRC Website at http://www.nrc.gov/reading-rm/adams.html(the Public Electronic Reading Room}.

Sincerely, IRAJ Paul G. Krohn, Chief Projects Branch 4 Division of Reactor Projects Docket Nos: 50-352, 50-353 License Nos: NPF-39, NPF-85

Enclosure:

Inspection Report 05000352/2008005 and 05000353/2008005 w/

Attachment:

Supplemental Information cc w/encl:

C. Crane, President and Chief Operating Officer, Exelon Generation M. Pacilio, Chief Operating Officer, Exelon Generation Company, LLC C. Mudrick, Site Vice President - Limerick Generating Station E. Callan, Plant Manager, Limerick Generating Station R. Kreider, Regulatory Assurance Manager R. DeGregorio, Senior Vice President, Mid-Atlantic Operations K. Jury, Vice President, Licensing and Regulatory Affairs P. Cowan, Director, Licensing D. Helker, Licensing B. Fewell, Associate General Counsel Correspondence Control Desk D. Allard, Director, PA Department of Environmental Protection J. Johnsrud, National Energy Committee, Sierra Club Chairman, Board of Supervisors of Limerick Township J. Powers, Director, PA Office of Homeland Security R. French, Director, PA Emergency Management Agency

NRC's document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html(the Public Electronic Reading Room).

Sincerely, IRA!

Paul G. Krohn, Chief Projects Branch 4 Division of Reactor Projects

• Docket Nos: 50-352, 50-353 License Nos: NPF-39, NPF-85 Distribution w/encl: (via E-mail)

S. Collins, RA M. Dapas, DRA D. Lew, DRP J. Clifford, DRP P. Krohn, DRP R. Fuhrmeister, DRP T. Setzer, DRP E. Torres, DRP E. DiPaolo, DRP, SRI N. Sieller, DRP, RI L. Pinkham, OA S. Campbell, RI, OEDO P. Bamford, PM, NRR \

E. Miller, NRR, Backup R. Nelson, NRR H. Chernoff, NRR ROPreports@nrc.gov Region I Docket Room (with concurrences)

SUNSI Review Complete: PGK (Reviewer's Initials)

DOCUMENT NAME: G:IDRPIBRANCH4IDRAFT INSPECTION REPORTS FOR BR 4 FO~R-",,=I4C!.TH~OTR 200S DRAFT REPORTSIUM 4TH OTR 200SIUM 200S-005REV2.DOC ML090330638 After declaring this document "An Official Agency Record" it will be released to the Public.

To receive a copy of this document, indicate in the box: ~CM =Copy without attachmenVendosure "E" =Copy With attachment/enclosure "N" = No copy OFFICE RIIDRP 1 RIIDRP L RIIDRP I NAME EDiPaolo/PGK for RFuhrmeister/RF PKrohnl PGK

[PATE 01/30109 01/30109 01/30109 OFFICIAL RECORD COpy

1 U.S. NUCLEAR REGULATORY COMMISSION REGION I Docket Nos: 50-352, 50-353 License Nos: NPF-39, NPF-85 Report No: 0500035212008005 and 05000353/2008005 Licensee: Exelon Generation Company, LLC Facility: Limerick Generating Station, Units 1 & 2 Location: Sanatoga, PA 19464 Dates: October 1,2008 through December 31, 2008 Inspectors: E. DiPaolo, Senior Resident Inspector N. Sieller, Resident Inspector T. Moslak, Health Physicist J. Baptist, Senior Project Engineer, Region II J. Caruso, Senior Operations Engineer R. Fuhrmeister, Senior Project Engineer K. Young, Senior Reactor Inspector B. Haagensen, Operations Engineer Approved by: Paul G. Krohn, Chief Projects Branch 4 Division of Reactor Projects Enclosure

2 TABLE OF CONTENTS

SUMMARY

OF FINDINGS ......................................................................................................... 3 REPORT DETAILS ..................................................................................................................... 4

1. REACTOR SAFETY ............................................................................................................... 4 1R01 Adverse Weather Protection .................................................................................... 4 1R04 Equipment Alignment .............................................................................................. 5 1R05 Fire Protection ......................................................................................................... 5 1R07 Heat Sink Performance .......................................................................................... 6 1R11 Licensed Operator Requalification Program ............................................................ 7 1R12 Maintenance Effectiveness ..................................................................................... 9 1R13 Maintenance Risk Assessments and Emergent Work Control ................................ 9 1R15 Operability Evaluations ......................................................................................... 10 1R18 Plant Modifications ................................................................................................ 10 1R19 Post-Maintenance Testing .................................................................................... 13 1R22 Surveillance Testing .............................................................................................. 15

4. OTHER ACTIVITES .............................................................................................................. 15 40A1 Performance Indicator (PI) Verification .................................................................. 15 40A3 Event Follow-up) .................................................................................................. 19 40A5 Other Activities ...................................................................................................... 19 40A6 Meetings, Including Exit. ........................................................................................ 20 SUPPLEMENTAL INFORMATION ......................................................................................... A-1 KEY POINTS OF CONTACT .................................................................................................. A-1 LIST OF ITEMS OPENED, CLOSED, AND DiSCUSSED ....................................................... A-1 LIST OF DOCUMENTS REVIEWED ...................................................................................... A-2 LIST OF ACRONyMS............ . ..............................................................................A-7 Enclosure

3

SUMMARY

OF FINDINGS IR 05000352/2008005,05000353/2008005; 10101/2008 - 1213112008; Limerick Generating Station, Units 1 and 2; Post-Maintenance Testing.

The report covered a three-month period of inspection by resident inspectors and announced inspections by regional reactor inspectors. One Green finding which was determined to be a non-cited violation (NCV) was identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process (SOP)." Findings for which the SOP does not apply may be Green or be assigned a severity level after NRC management review. Cross-cutting aspects associated with findings are determined using IMC 0305, "Operating Reactor Assessment Program," dated January 2009. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight," Revision 4, dated December 2006.

A. NRC-Identified and Self-Revealing Findings Cornerstone: Mitigating Systems

• Green. The inspectors identified a NCV of Technical Specification 6.8.1, "Administrative Controls-Procedures", because Exelon did not maintain adequate maintenance procedures associated with work performed on the Unit 2 Nuclear Steam Supply Shutoff System (NSSSS). Specifically, the procedures, which performed system relay replacements, did not contain adequate post-maintenance testing (PMT) to demonstrate that the Technical Specification required response times of all circuits affected by the maintenance were satisfied.

The inspectors determined that this finding was more than minor because it was associated with the procedure quality attribute of the Mitigating System cornerstone, and affected the Mitigating System cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. As a result of the inadequate PMT, additional unavailability was accrued, and an engineering evaluation was required to demonstrate satisfactory response times. The finding was determined to be of very low safety significance (Green) because it did not represent a loss of safety function. The inspectors determined this finding had a cross-cutting aspect in Human Performance, Resources, because Exelon did not provide complete and accurate work packages to assure nuclear safety. Specifically, the NSSSS was returned to service without all the required post-maintenance testing being performed to demonstrate operability. [I MC 0305 aspect:

H.2(c) (Section 1R19)

B. Licensee-Identified Violations None.

Enclosure

4 REPORT DETAILS Summary of Plant Status Unit 1 began the inspection period operating at full rated thermal power (RTP). On December 6, 2008, operators reduced power to approximately 95 percent to facilitate a control tod pattem adjustment. Full RTP was achieved later that day. On December 20, 2008, power was reduced to approximately 94 percent to facilitate main turbine valve testing. Operators returned power to full RTP on December 21, 2008. Unit 1 operated at full RTP for the remainder of the inspection period.

Unit 2 began the inspection period operating at full RTP. On October 18, 2008, operators reduced power to approximately 80 percent to facilitate a control rod pattern adjustment. Full RTP was achieved on October 19, 2008. On October 28, 2008, an unplanned downpower to approximately 25 percent was performed due to drywell temperature exceeding Technical Specification (TS) allowed limits. This was caused by a loss of drywell cooling that resulted when the 2A Drywell Chiller tripped while the 2B Drywell Chiller was out-of-service (OOS) for planned maintenance. Power was returned to full RTP later that day following the restoration of the 2B Drywell Chiller to service, and the subsequent lowering of drywell temperature to below the TS required limit. On November 1,2008, operators reduced power to approximately 80 percent to facilitate a planned control rod pattern adjustment. Full RTP was reached on November 2,2008. On December 13,2008, operators reduced power to approximately 80 percent to facilitate a control rod pattern adjustment, main steam isolation and main turbine valve testing, and main condenser tube and waterbox cleaning. Full RTP was achieved on December 14, 2008. Unit 2 operated at full RTP for the remainder of the inspection period.

1. REACTOR SAFETY Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity 1RO 1 Adverse Weather Protection

.1 System Seasonal (71111.01-1 sample)

a. Inspection Scope The inspectors assessed the effectiveness of the licensee's cold weather protection program as it related to ensuring that the facility's emergency diesel generators, standby liquid control system, and condensate storage tank low level switches would remain functional and available in cold weather conditions. In addition to reviewing the licensee's program-related documents and procedures, walkdowns were conducted of the freeze protection equipment (e.g., heat tracing, area space heaters, etc.) associated with the above systems/components. Licensee problem identification and resolution associated with cold weather protections was also assessed. Documents reviewed are listed in the Attachment.

b. Findings No findings of Significance were identified.

Enclosure

5

.2 Site Imminent Weather Conditions (7111 f01 - 1 sample)

a. Inspection Scope The inspectors evaluated Exelon's implementation of adverse weather preparation procedures and compensatory measures as a result of a high winds warning that was issued for the site area on December 31, 2008. The inspectors toured risk-significant and susceptible plant areas to verify procedures and compensatory measures were implemented before the onset of the adverse weather conditions. The inspectors reviewed associated issues entered into the CAP to verify that they were properly characterized for resolution. Documents reviewed are listed in the Attachment.

b. Findings No findings of significance were identified.

1R04 Eguipment Alignment Partial Walkdown (71111.04Q - 4 samples)

a. Inspection Scope The inspectors performed partial walkdowns of the plant systems listed below to verify their operability when safety-related equipment in the opposite train was either inoperable, undergoing surveillance testing, or potentially degraded. The inspectors used TS, Exelon operating procedures, plant piping and instrumentation drawings (P&IDs), and the Updated Final Safety Analysis Report (UFSAR) as guidance for conducting partial system walkdowns. The inspectors reviewed the alignment of system valves and electrical breakers to ensure proper in-service or standby configurations as described in plant procedures and drawings. During the walkdowns, the inspectors evaluated the material condition and general housekeeping of the systems and adjacent spaces. The documents reviewed are listed in the Attachment. The inspectors performed walkdowns of the following areas:

• 021 Emergency Diesel Generator (EDG) walkdown while 011 EDG was OOS for monthly surveillance test;

• Offsite power and safeguards DC (Direct Current) power while Offsite Sus 10 was for planned maintenance;

• Unit 1 High Pressure Coolant Injection (HPCI) while Unit 1 Reactor Core Isolation Cooling (RCIC) OOS for planned maintenance; and

• Unit 1 'S' Loop of Suppression Pool Cooling while 'A' Loop was OOS for planned maintenance.

b. Findings No findings of significance were identified.

1R05 Fire Protection

.1 Fire Protection - Tours (71111.05Q - 5 samples)

a. Inspection Scope Enclosure

6 The inspectors conducted a tour of the five areas listed below to assess the materiar .

condition and operational status of fire protection features. The inspectors verified that combustibles and ignition sources were controlled in accordance with Exelon's administrative procedures. Fire detection and suppression equipment was verified to be available for use, and passive fire barriers were verified to be maintained in good material condition. The inspectors also verified that station personnel implemented compensatory measures for OOS, degraded, or inoperable fire protection equipment in accordance with the station's tire plan. The documents reviewed are listed in the Attachment. The inspectors toured the following areas:

• Unit 1 RCIC Room, Fire Area 33;

• Unit 1 HPCI Room, Fire Area 34;

• Unit 2 RCIC Room, Fire Area 56;

• Unit 2 HPCI Room, Fire Area 57; and

• Unit 2 Control Rod Drive Equipment and Neutron Monitoring Area Room, Fire Area 68.

b. Findings No findings of significance were identified .

.2 Fire Protection - Drill Observation (71111.05A - 1 sample)

a. Inspection Scope The inspectors observed one u~announced fire drill conducted near the Unit 1 Hydrogen Seal Oil Skid on December 8, 2008. The inspectors observed the drill tt? evaluate the readiness of the plant fire brigades to fight fires. The documents reviewed are listed in the Attachment. Specific attributes evaluated were:

• Proper donning of fire fighting turnout gear and self-contained breathing apparatus;

• Proper use and layout of fire hoses;

• Ernployrnent of appropriate fire fighting techniques;

• Sufficient fire fighting equipment brought to the scene;

• Effectiveness of fire brigade leader communications, command, and control;

• Search for propagation of fire into other plant areas;

• Utilization of pre-planned strategies;

• Adherence to the pre-planned drill scenario; and

• Licensee self-critique and exercise evaluation.

b. Findings No findings of Significance were identified.

1R07 Heat Sink Perforrnance (71111.07A - 2 sarnples)

a. Inspection Scope The inspectors reviewed the results of Exelon's thermal performance tests for the safety-related room coolers listed below to assess the capability of the coolers to operate as designed. The inspectors reviewed the UFSAR, supporting design calculations, therrnal Enclosure

7 perform<.lnce c<.llcul<.ltions, <.lnd historic<.ll trend information to ensure the room coolers were capable of removing the required heat load during accident conditions. The inspectors verified that issues' identified during the thermal performance tests were entered into the licensee's CAP for evaluation. The documents reviewed are listed in the Attachment. The inspectors reviewed the results of the following tests:

• 2BV210 Residual Heat Removal (RHR) Room Cooler Air to Water Heat Transfer Test; and

• 1EV211 Core Spray Room Cooler Air to Water Heat Transfer Test.

1R11 Licensed Operator Regualification Program

.1 Quarterly Licensed Operator Reg ualification Activities (71111.11 Q - 1 sample)

On November 4, 2008, the inspectors evaluated the 'A' operating crew licensed operator requalification simulator examination, LSES-2006, "Simulator Evaluation Scenario,"

Revision 6. The scenario tested the operators' ability to respond to failures of equipment as well as a loss-of-coolant accident with equipment OOS and emergency core cooling system failures. The inspectors observed licensed operator performance including operator critical tasks, which are required to ensure the safe operation of the reactor and protection of the nuclear fuel and primary containment barriers. The inspectors also assessed crew dynamics and supervisory oversight to verify the ability of operators to properly identify and implement appropriate TS actions, regulatory reports, and notifications. The inspectors observed and reviewed the training evaluators' grading and critiques and assessed whether appropriate feedback was provided to the licensed operators.

a. Findings No findings of significance were identified .

.2 Biennial Regualification Program Review (71111.11 - 1 sample)

a. Inspection Scope The following inspection activities were performed on a sampling basis using NUREG-1021, Revision 9, Supplement 1, "Operator Licensing Examination Standards for Power Reactors," Inspection Procedure Attachment 71111.11, "Licensed Operator Requalification Program," NRC Manual Chapter 0609, Appendix I, "Operator Requalification Human Performance Significance Determination Process (SOP)," and 10 CFR 55.46, "Simulator Rule" as acceptance criteria.

The inspectors reviewed documentation of operating history since the last requalification program inspection. The inspectors also discussed facility operating events with the

~ -"

resident staff. Documents reviewed included NRC inspection reports, and licensee issue reports (IRs) that involved human performance issues for licensed operators to ensure that operational events were not indicative of possible training deficiencies (see document list attached).

The inspectors reviewed three sets each of 2008 simulator scenarios and job performance measures (JPMs) administered during this current exam cycle (i.e., weeks Enclosure

8 1, 4, and 5) to ensure the quality of these examinations met or exceeded the criteria established in the Examination Standards and 10 CFR 55.59.

The inspectors observed the administration of operating examinations to Delta operating crew and Staff Crew 1. The operating examinations consisted of two crew simulator scenarios and one set of five JPMs administered to each individual.

Conformance with Simulator Requirements Specified in 10 CFR 5!j.46 For the site specific simulator, the inspectors observed simulator performance during the conduct of the examinations, and discrepancy reports to verify compliance with the requirements of 10 CFR 55.46. The following areas were reviewed:

Reviewed a sample of simulator tests including transients, malfunctions, and core performance tests. Verified that a sample of completed simulator work requests (SWRs) from the past year effectively addressed the described issue. The specific simulator tests reviewed are listed in the Attachment.

Conformance with operator license conditions was verified by reviewing the following records:

• Ten medical records. The inspectors confirmed all records were complete, that restrictions noted by the doctor were reflected on the individual's license and that the physical examinations were qiven within 24 months;

• Proficiency watch-standing and reactivation records. A sample elf one licensed operator reactivation record was reviewed as well as a 100 percent sample of non-shift licensed personnel watCh-standing documentation for time on shift to verify currency and conformance with the requirements of 10 CFR 55; and

• Remediation training records. The inspectors reviewed records for five operators from the past year training cycle.

Licensee's Feedback System.

The inspectors interviewed instructors, training/operations management personnel, and six licensed operators for feedback regarding the implementation of the licensed operator requalification program to ensure the requalification program was meeting their needs and responsive to their noted deficiencies/recommended changes. .

On November 21,2008, the inspectors conducted an in-office review of licensee requalification examination results. These results included the annual operating tests only. The comprehensive written exams were administered and the results evaluated last year. The inspection assessed whether pass rates were consistent with the guidance of NRC Manual Chapter 0609, Appendix I, "Operator Requalification Human Performance Significance Determination Process (SOP)." The inspectors verified that:

• Crew failure rate on the dynamic simu lator was less than 20 percent.

(Failure rate was 0.0 percent);

• Individual failure rate on the dynamic simulator test was less than or equal to 20 percent. (Failure rate was 0.0 percent);

Enclosure

9

• Individual failure rate on the walkthrough test (JPMs) was less than or equal to 20 percent. (Failure rate was 2.0 percent); and

• More than 75 percent of the individuals passed all portions of the examination (100 percent of the individuals passed all portions of the examination).

Note: One licensed operator on short term disability was not able to complete all of his licensed operator requalification training (cycles 0805 and 0806) and his NRC required annual operating examination at this time. He is being administratively restricted from license duties and will not be permitted to resume his license duties until he successfully completes all missed training and successfully passes his annual operating examination (IR 847625).

b. Findings No findings of significance were identified.

1R12 Maintenance Effectiveness (71111.12 - 4 samples)

a. Inspection Scope The inspectors evaluated Exelon's work practices and follow-up corrective actions for structures, systems, and components (SSCs) and identified issues to assess the effectiveness of Exelon's maintenance activities. The inspectors reviewed the performance history of risk significant SSCs and assessed Exelon's extent-of-condition determinations for those issues with potential common cause or generic implications to evaluate the adequacy of the station's corrective actions. The inspectors assessed Exelon's problem identification and resolution actions for these issues to evaluate whether Exelon had appropriately monitored, evaluated, and dispositioned the issues in accordance with Exelon procedures and the requirements of 10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance." In addition, the inspectors reviewed selected SSC classifications, performance criteria and goals, and Exelon's corrective actions that were taken or planned, to evaluate whether the actions were reasonable and appropriate. The documents reviewed are listed in the Attachment. The inspectors performed the following samples:

• Redundant Reactivity Control System for the period October 2006 - October 2008;

• Control Enclosure Chilled Water for the period December 2006 - December 2008;

• IR 751491, EDG D14 K1 relay contractor failure; and

• IR 760581, Medium voltage cable manhole water intrusion.

b. Findings No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13 - 4 sampleS)

a. Inspection Scope The inspectors evaluated the effectiveness of Exelon's maintenance risk assessments required by 10 CFR 50.65(a)(4). This inspection included discussion with control room operators and risk analysis personnel regarding the use of Exelon's on-line risk monitoring software. The inspectors reviewed equipment tracking documentation, daily Enclosure

10 work schedules, and performed plant tours to gain assurance that the actual plant configuration matched the assessed configuration. Additionally, the inspectors verified that Exelon's risk management actions, for both planned and emergent work, were consistent with those described in Exelon procedure, ER-AA-600-1042, "On-Line Risk Management." The documents reviewed are listed in the Attachment. Inspectors reviewed the following samples:

• IR 826565, Emergent unavailability of 2B Instrument Air Compressor with 20 Start-up

• Transformer and one 2B RHR room cooler OOS;

• IR 836603, Emergent unavailability of 2A Orywell Chiller with 2B Orywell Chiller OOS;

• IR 839237, Unit 1 HPCI declared inoperable due to flow circuit problems with Offsite Bus 10 OOS for planned maintenance; and

• IR 859270, Emergent unavailability of a Control Enclosure Chiller due to a low freon trip locked in.

b. Findings No findings of Significance were identified.

1R15 Operability Evaluations (71111.15 - 5 samples)

a. Inspection Scope For the five operability evaluations described below, the inspectors assessed the technical adequacy of the evaluations to ensur.e that Exelon properly justified TS operability and verified that the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors reviewed the UFSAR to verify that the system or component remained available to perform its intended safety function. In addition, the inspectors reviewed compensatory measures implemented to ensure that the measures worked and were adequately controlled. The inspectors also reviewed a sample of issue reports to verify that Exelon identified and corrected deficiencies associated with operability evaluations. The documents reviewed are listed in the Attachment. The inspectors performed the following evaluations:

• IR 824770, Emergency Service Water (ESW) System flow control valve to 'A' Main Control Room Chiller Condenser, does not fully close;

• IR 831482, Isolation Actuation Instrumentation past operability following system relay replacements;

• IR 836603, Impact of Orywell Temperature on Reactor Vessel Level Indication Operability;

• IR 839237, Flow oscillations on Unit 1 HPCI when shut down; and

• IR 840654, Components missing from containment in-service inspection program.

b. Findings No findings of significance were identified.

1R18 Plant Modifications

.1 Temporary Modifications (71111.18 - 2 samples)

Enclosure

+ 11

a. Inspection Scope The inspectors reviewed two temporary plant modifications, listed below. The inspectors reviewed the design adequacy of the modification for material compatibility which included functional properties, environmental qualification, and seismic evaluation. The inspectors compared the temporary change with the UFSAR and TS to verify that the modification did not affect system operability or availability. The inspectors ensured that station personnel implemented the modification in accordance with the applicable temporary configuration change process. Where applicable, the inspectors verified that modification preparation, staging, and implementation did not impair emergency/abnormal operating procedure actions and key safety functions. Post-modification testing was reviewed to confirm that operability was established, unintended system interactions did not occur, and modification acceptance criteria were met.

Documents reviewed are listed in the Attachment. The following temporary modifications were reviewed:

• Temporary Procedure Change to ST-6-011-232-0, 'B' Loop ESW Pump, Valve and Flow Test; and

• Temporary plant modification to add vibration monitoring equipment for HV 2F050A (B).

b. Findings No findings of significance were identified .

.2 Permanent Modifications (71111.18 -1 sample)

a. Inspection Scope The inspectors reviewed one permanent plant modification documented in Engineering Change LG 99-00682, Limerick Technical Specification Bases Changes to 3.8.1, Offsite Power. The inspectors reviewed the modification and associated 10 CFR 50.59 evaluation to verify consistency with the Limerick licenSing bases. The documents reviewed are listed in the Attachment.

a. Findings

Introduction:

The inspectors identified an unresolved item (URI) associated with changes Exelon made to the TS Bases associated with TS 3.8.1, "AC Sources-Operating."

Description:

On September 30, 2008, operators racked out one of the two offsite power supply feeder breakers to 4kV Emergency Bus 011 (201-011) for maintenance. The inspectors noted that although one of the two offsite power sources was not available to 4kV Emergency Bus 011, operators did not declare the associated offsite power circuit (201 Circuit) inoperable and enter into TS Limiting Condition for Operation (LCO) 3.8.1.1, AC Sources - Operating, Action f, which requires, in part, performing Surveillance Requirement (SR) 4.8.1.1.a within one hour and also entails entering a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> LCO shutdown action statement. The inspector noted that TS SR 4.8.1.1.1.b could not be met if one of the two offsite power source breakers was racked out. That SR states "Each of the above required independent circuits between the offsite transmission Enclosure

12 network and the onsite Class 1 E distribution system shall be demonstrated OPERABLE in accordance with the Surveillance Frequency Control Program by transferring, manually and automatically, unit power supply from the normal circuit to the alternate circuit." With an offsite power supply feeder breaker racked out and unavailable to an onsite 4kV emergency bus, manual and automatic transfer was not possible. In addition, TS 4.0.1 states, in part, that, "Failure to meet a Surveillance, whether such failure is experienced during the performance of a Surveillance or between performances of the

• Surveillance, shall be failure to meet the Limiting Condition for Operation."

The inspectors referenced TS Bases 3/4.8.1, which described that an offsite circuit is considered to be inoperable if it is not capable of supplying at least three, Unit 1 4kV emergency buses. Recognizing that the TS Bases 3/4.8.1 appeared to conflict with the SR, the inspectors questioned the history of the bases. Exelon informed the inspectors that the bases were modified in 2000 to define an operable offsite source as one capable of supplying power to three of the four emergency buses in the unit, through Engineering Change Request (ECR) LGS ECR 99-00682.

The inspectors reviewed LGS ECR 99-00682 and found that Exelon's 10 CFR 50.59 screening for the TS bases change concluded that the change was an enhancement, and, as such, a change to the TS was not required. The ECR described the change as taking advantage of system redundancy similar to the design of the EDGs. Specifically, section 8.3.1.1.2.2 of the UFSAR provides results of a single failure analysis (focused on the EDGs but also applicable to the 4kV emergency buses) that concludes that any combination of three-out-of-four buses could withstand a single failure and still safely shut down the plant. The inspectors reviewed the Limerick licensing basis and found 1 several conflicts with Exelon's conclusion. Namely, the TS bases change:

• Conflicted with the facility as described in the UFSAR Sections 8.2.1, "Offsite Power Sources." Section 8.2.1.1 describes that "Both offsite sources are available continuously to the Class 1E buses"; and

• Conflicted with the description of the onsite emergency power system description as documented in NUREG-0991, "Safety Evaluation Report Related to the Operation of Limerick Generating Station, Units 1 and 2," dated August 1983. Section 8.3.1 of the Safety Evaluation Report stated that "Each 4.16-kV ESF (Engineered Safety Feature) bus is normally connected to two offsite power sources, designated as preferred and alternate power supply ... ;" and,

• Although the ECR described the change as taking advantage of system redundancy similar to the design of the EDGs, the inspector noted that a TS Action is required to be entered for one EDG being inoperable.

The inspectors determined that the modification of the TS bases appeared to be in conflict with the requirements of TS LCO 3.8.1.1 through the application of SR 4.8.1.1.1.b. Therefore, it appeared that the change should have required a change to the TS, which would have required NRC review. Making the TS bases change without changing the TS appeared to be contrary to 10 CFR 50.59 (c)(1)(i) which states that "a licensee may make changes in the facility as described in the final safety analysis report ... without obtaining a license amendment pursuant to [paragraph] 50.90 only if a change to the technical specifications incorporated in the license is not required." In addition, the changes made to the TS bases appeared to be contrary to TS 6.8.4.h, "Technical Specification Bases Control Program," which contains similar requirements.

Enclosure

13 Exelon acknowledged the inspectors observations and agreed to provide additional

'information to show that the changes made to the TS bases did not require prior NRC approval. Pending the review of the additional information to be provided by Exelon, this issue is unresolved. (URI 05000352, 353/2008005-01, Changes to Technical Specification 3.8.1 Bases) 1R19 Post-Maintenance Testing (71111.19 - 6 samples)

a. Inspection Scope The inspectors reviewed the six post-maintenance tests (PMTs) listed below to verify that procedures and test activities ensured system operability and functional capability.

The inspectors reviewed Exelon's test procedures to verify that the procedures adequately tested the safety functions that may have been affected by the maintenance activity, and that the acceptance criteria in the procedures were consistent with information in the licensing and design basis documents. The inspectors also witnessed the test or reviewed test data to verify that the results adequately demonstrated restoration of the affected safety functions. The documents reviewed are listed in the Attachment. The inspectors performed the following samples:

• C0226609, Replace main steam isolation valve logic relays;

• A1684886, Scram Discharge Volume Drain Primary Containment Isolation Valve actuator leak repair;

• C0226733, Repair Primary Containment Isolation Valve Actuator;

• C0226197, Rebuild Auxiliary Equipment Room Differential Pressure Control Damper;

• C0226274, Replace EDG D13 K1 contactor with new model; and

• R0856209, Unit 1 'A' RHR pump minimum flow valve (HV-051-1F007A), breaker preventive maintenance.

b. Findings

Introduction:

The inspectors identified an NCVofTechnical Specification 6.8.1, "Administrative Controls-Procedures", because Exelon did not maintain adequate maintenance procedures associated with work performed on the Unit 2 Nuclear Steam Supply Shutoff System (NSSSS).

Description:

On October 14, 2008, maintenance personnel performed time response testing of the logic circuitry associated with the IB channel of Unit 2 NSSSS with unsatisfactory results. Technical Specification Limiting Condition for Operation 3.3.2, "Isolation Actuation Instrumentation," requires the isolation system instrumentation response time associated with Main Steam Line Flow-High to be less than or equal to 0.5 seconds. Because the response time for this function was greater than allowed by TS, Exelon replaced several relays in the logic channel per Work Order (WO)

C0226609. Post-maintenance surveillance testing was performed on the IB channel per TS SR 4.3.2.3, which verifies time response for the channel is within TS allowed limits.

The channel satisfactorily passed the post-maintenance test and was returned to an operable status later that day.

On October 15, 2008, the inspectors reviewed the post-maintenance testing performed for the maintenance. During the review the inspectors noted that one of the replaced relays (B21 H-K18D) was common to the liB channel of the NSSSS. The inspector Enclosure

14 questioned whether response time testing the liB channel was appropriate because the common relay was replaced. Exelon concluded that response time of liB channel could have been affected by the replacement of relay B21-K18D.

Meanwhile, on October 15, similar maintenance and testing was completed on the Unit 2 IA NSSSS channel per WO C0225812. During the maintenance relay B21-K18A (similar to B21-K18D on the IB channel) was replaced. This relay shared common logic with the IIA channel, but post-mainte!nance testing was only performed on the IA channel.

Operators initially declared the NSSSS system operable upon satisfactory completion of the IA channel post-maintenance test. However, upon notification of the inspectors' questions regarding the adequacy of post-maintenance testing, operators declared the IIA channel inoperable at around 7:00 p.m. Exelon performed the required testing on the IIA channel to demonstrate the response time was within TS allowed limits. The results of the testing were satisfactory and the channel was declared operable on October 16, 2008 at 11 :03 a.m.

For the liB channel, Exelon performed an evaluation of data from past and recent testing. Conservative summation times were used to conclude that TS required response times were met.

The inspectors determined that Exelon's failure to provide complete and accurate work packages (C0226609 and C0225812) to adequately test the response times of the Unit 2 NSSSS logic channels following relay replacements was a performance deficiency.

Analysis: This finding was more than minor because it was associated with the Procedure Quality attribute oftthe Mitigating System cornerstone, and affected the Mitigating System cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. As a result of the inadequate PMT, additional unavailability was accrued, and an engineering evaluation was required to demonstrate satisfactory response times. The inspector assessed the finding using Phase 1 of IMC 0609, Appendix A, "Significance Determination Process for Reactor Inspection Findings for At-Power Situations" and determined the finding to be of very low safety Significance (Green) because it did not represent a loss of safety function.

This finding has a cross-cutting aspect in Human Performance, Resources, because Exelon did not provide complete and accurate work packages to assure nuclear safety (H.2(c)). This resulted in the affected channels of the NSSSS being returned to service without all the required post-maintenance testing being performed to demonstrate operability.

Enforcement: Technical Specification 6.8.1 states, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures as recommended in NRC Regulatory Guide (RG) 1.33, Appendix A, February, 1978. NRC Regulatory Guide 1.33, Appendix A, Section 9, requires procedures for the performance of maintenance. Contrary to the above, on October 14 and October 15, 2008, corrective work orders C0226609 and C0225812 were performed on Unit 2 to replace Main Steam Line Flow - High NSSSS logic relays, and did not contain adequate procedural steps to assure all required post-maintenance testing was performed to establish operability.

Specifically, although C0226609 and C0225812 replaced relays that could have affected the time responses of the II Band IIA channels, respectively, the work orders did not include steps to test the channels to assure that the time response remained within Enclosure

Technical Specification allowed limits. As a result, 'additional unavailability was accrued, and an engineering evaluation was required to demonstrate satisfactory response times.

Corrective actions included testing the missed relays and performing system evaluations. Because the finding is of very low safety significance and has been entered into Exelon's CAP as Issue Report (IR) 831482 and 831567, this violation is being treated as a non-cited violation, consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 05000353/2008005002, Inadequate Post-Maintenance Test following Containment Isolation System Relay Replacement) 1R22 Surveillance Testing (71111.22 - 5 samples)

a. Inspection Scope The inspectors either witnessed the performance of, or reviewed test data for, five surveillance tests (STs) associated with risk-significant SSCs. The reviews verified that Exelon personnel followed TS requirements and that acceptance criteria were appropriate. The inspectors also verified that the station established proper test conditions, as specified in the procedures, that no equipment preconditioning activities occurred, and that acceptance criteria were met. The documents reviewed are listed in the Attachment. The inspectors reviewed STs for the following systems and components:

• ST-5-041-800-1, Unit 1 Reactor Coolant System Chemistry Sample, Revision 19;

• ST 092-365-0, Inoperable Unit 1 Safeguard Power Supply Actions, Units 1 and 2;

• ST-2-041-911-2, NSSSS Main Steam Line Flow-High; Division 11b Channel D Response Time Test;

• ST-6-011-232-0, 'B' Loop ESW Pump, Valve and Flow Test (In-service test); and

• ST-6-1 07-596-1 (2), Drywell floor drain supply equipment drain tank surveillance.

b. Findings No findings of significance were identified.

4. OTHER ACTIVITES 40A1 Performance Indicator (PI) Verification

.1 Mitigating Systems and Barrier Integrity Cornerstone Pis The inspectors sampled Exelon's submittal of the Mitigating Systems and Barrier Integrity cornerstone Pis listed below to verify the accuracy of the data recorded from October 2007 though September 2008. The inspectors utilized performance indicator definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, "Regulatory Assessment Perforrnance Indicator Guidelines," Revision 5, to verify the basis in reporting for each data element. The inspectors reviewed various documents, including portions of the main control room logs, issue reports, power history curves, work orders, and system derivation reports. The inspectors also discussed the method for compiling and reporting performance indicators with cognizant engineering personnel and compared graphical representations from the most recent performance indicator (PI) report to the raw data to verify that the report correctly reflected the data. The documents reviewed are listed in the Attachment.

Enclosure

16 Cornerstone: Mitigating Systems (71151 - 2 samples)

• Units 1 and 2 MSPI Cooling Water Cornerstone: Barrier Integrity (71151 - 4 samples)

• Units 1 and 2 Reactor Coolant System Leakage

• Units 1 and 2 Reactor Coolant System Activity *

b. Findings No findings of significance were identified .

.2 Occupational Exposure Control Effectiveness

a. Inspection Scope (71151 - 1 sample)

The inspector reviewed implementation of the licensee's Occupational Exposure Control Effectiveness PI Program for the period September 2007 through September 2008.

Specifically, the inspector reviewed electronic dosimetry alarm reports, issue reports, and associated documents, for occurrences involving locked high radiation areas, very high radiation areas, and unplanned exposures against the criteria specified in NEI 99-02, "Regulatory Assessment Performance Indicator Guideline," to verify that all occurrences that met the NEI criteria were identified and reported as performance indicators. This inspection activity represents the completion of one (1) sample relative to this inspection area; completing the annual inspection requiremeht.

b. Findings No findings of Significance were identified .

.3 RETS/ODCM Radiological Effluent Occurrences

a. Inspection Scope (71151 - 1 sample)

The inspector reviewed relevant effluent release condition reports for the period September 2007 through September 2008, for issues related to the public radiation safety performance indicator, which measures radiological effluent release occurrences that exceed 1.5 mrem/qtr whole body or 5.0 mrem/qtr organ dose for liquid effluents; 5mrads/qtr gamma air dose, 10 mrad/qtr beta air dose, and 7.5 mrads/qtr for organ dose for gaseous effluents. This inspection activity represents the completion of one (1) sample relative to this inspection area; completing the annual inspection requirement.

The inspector reviewed the following documents to ensure the licensee met all requirements of the performance indicator.

• Monthly projected dose assessment results due to radioactive liquid and gaseous effluent releases;

• Quarterly projected dose assessment results due to radioactive liquid and gaseous effluent releases; and

• Dose assessment procedures.

Enclosure

17

b. Findings  :,~.

No findings of significance were identified.

40A2 Identification and Resolution of Problems (CAP)

.1 Review of Items Entered into the Corrective Action Program As required by Inspection Procedure 71152, "Identification and Resolution of Problems,"

and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors screened all items entered into Limerick's corrective action program. The inspectors accomplished this by reviewing each new condition report, attending management review committee meetings, and accessing Exelon's computerized database .

.2 Semi-Annual Review to Identify Trends

a. Inspection Scope (71152 - 1 sample)

As required by inspection procedure 71152, "Identification and Resolution of Problems,"

the inspectors performed a review of Exelon's CAP and associated documents to identify whether trends existed that would indicate a more significant safety issue. The review considered the period of July through December 2008 and was focused on repetitive equipment issues. The results of routine inspector CAP item screening, Exelon's trending efforts, and human performance results were also considered. The inspectors reviewed issues documented outside the normal CAP such as Plant Health Committee reports including the Top Ten Equipment Issues List, the Plant Health Committee Issues List, and the Open Action Items List. The inspectors compared and contrasted their results with the results contained in the Limerick Generating Station Performance Trending reports for the third quarter 2008.

b. Findings and Observations No findings of significance were identified. The inspectors identified a negative trend in Exelon's maintenance rule program. During the review period the inspectors identified several issues associated with the evaluation of equipment issues which resulted in' missed and/or improper functional failure (FF) or maintenance preventable functional failure (MPFF) determinations as follows:

• IR 718479 was written due to an issue with the Redundant Reactivity Control System (RRCS). This issue was reviewed by the Reactor Protection System manager and determined to not be a FF for that system; however the system manager recognized that the issue should be reviewed by the RRCS manager as well. Due to an administrative error, the IR was closed out before the RRCS system manager reviewed the issue. This was later identified by the inspectors, and further review by Exelon determined the failure was a FF for the RRCS system. Exelon placed this issue into the CAP as IR 834878.

• IR 800295 was written due to a failed surveillance related to low frequency associated with EDG D14. Due to an administrative error, the IR was closed to an investigation related to VAR swings associated with the same EDG. The Enclosure

18 inspectors identified that, as a result of closing the IR, the low frequency event was never reviewed to determine if it was a FF. Exelon placed this issue into the CAP as IR 821372. Subsequent evaluation determined that the low frequency event was not a FF.

• IR 798687 was written due to an issue related to VAR swings on EDG D14 during surveillance testing. The investigation of the issue determined that the failure was not a FF based on a preliminary investigation determination that the

• VAR swings would occur only while the EDG is in the test mode. However, further investigation of the issue determined that the VAR swings were caused by erratic operation of the voltage regulator due to vibrations. The inspectors identified that the FF determination was not re-investigated based on the final results of the final apparent cause evaluation. Exelon placed this issue into the CAP as IR 824522. Subsequent evaluation of the issue concluded that the failure was a FF but not a MPFF. However, the inspectors pointed out notable differences between the conclusions of the MPFF determination and the apparent cause evaluation for the failure. Based on the inspector's observation, the erratic operation of the voltage regulator was determined to be a MPFF.

• IR 751491 was written due to an issue associated with the EDG D14 voltage regulator (K1 contactor failure). The issue was determined to not be a FF by the system manager based on the failure occurring when the EDG was not required to be available (i.e., during a refueling outage). The inspectors questioned this determination because the K1 contactor failure could have occurred during a true demand. Exelon placed this issue into the CAP as IR 817091. Subsequent evaluation determined that the failure was a FF. t

• IR 801316 was written due to a "B" main control room (MCR) chiller trip in July 2008. The licensee's investigation determined the cause of the trip was a failed capacity control module (CCM). The issue was reviewed by the system manager and determined to be a functional failure, but not a MPFF. The inspectors challenged that the failure should be a MPFF, because there was a previous opportunity to establish preventative maintenance for this component.

Specifically, the inspectors identified that a 2A drywell chiller CCM failed in 2005 (IR 348392), and the licensee's extent-of-condition review recognized that the four drywell chillers and two control room chillers all had CCMs that operated similarly to the failed CCM. The licensee established preventive maintenance for the drywell chiller CCMs, but failed to establish a PM for the control enclosure chillers. The system manager agreed to reevaluate IR 801316, and this review is ongoing.

The inspectors determined that each of the individual issues was minor. However, because of the quantity of issues identified during the review period, the issues indicated a negative trend in maintenance rule program function failure determinations. As a result of some of the above issues identified by the inspectors, as well as other issues identified by the site's Nuclear Oversight organization, Exelon wrote IR 840929 to perform a common cause analysis of the collective issues .

.3 Annual Sample: Valve HV-051-2F024A Internal Failure

a. Inspection Scope (71152 - 1 sample)

Enclosure

19 The inspectors reviewed the licensee's corrective actions associated with IR 654041, regarding Unit 2 RHR Suppression Pool Cooling Valve HV-051-2F024A stem-to-disk separation. The inspectors reviewed system operating procedures, applicable technical evaluations, system drawings, work orders, design basis documents, and related internal and external operating experience to ensure that the licensee exercised appropriate actions in accordance with the requirements of their corrective action program.

b. Findings and Observations No findings of significance were identified. The inspectors confirmed that the valve failure mechanism was unique to the subject valve and did not adversely affect the safety function of the valve. Additionally, the inspectors verified that comparable valves were evaluated by the licensee to ensure that similar failure mechanisms were unlikely and would not adversely affect the safety function of the specific systems. The inspectors also confirmed that the licensee appropriately categorized and prioritized this issue in their corrective action program.

40A3 Event Follow-up (71153 - 1 sample)

a. Inspection Scope The inspectors reviewed plant parameters and evaluated performance of plant equipment when Unit 2 performed an unplanned downpower to approximately 25 percent on October 28, 2008. The down power was required due to the Unit 2 drywell temperature exceeding the TS allowed limit, which was caused by the failure of the 2A Drywell Chiller while the 2B Drywell Chiller was OOS for planned maintenance.

Operators returned the plant to full RTP later that day following the restoration of the 2B Drywell Chiller and subsequent lowering of drywell temperature to below the TS allowed limit. The inspectors communicated the event to appropriate regional personnel and compared the event details with criteria contained in IMC 0309, "Reactive Inspection Decision Basis for Reactors," for consideration of additional reactive inspection activities.

The inspectors verified that Exelon entered the issue into the CAP for resolution.

b. Findings No findings of significance were identified.

40A5 Other Activities

.1 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope During the inspection period the inspectors conducted observations of security force personnel and activities to ensure that the activities were consistent with licensee security procedures and regulatory requirements relating to nuclear plant security.

These observations took place during both normal and off-normal plant working hours.

These quarterly resident inspector observations of security force personnel and activities did not constitute any additional inspection samples. Rather, they were considered an integral part of the inspectors' normal plant status review and inspection activities.

Enclosure

20

b. Findings No findings of significance were identified .

.2 Implementation of Temporary Instruction (T1)2515/176 - Emergency Diesel Generator Technical Specification Surveillance Reguirements Regarding Endurance and Margin Testing (TI-2515/176 - 1 sample)

a. Inspection Scope The objective of TI 2515/176, "Emergency Diesel Generator Technical Specification Surveillance Requirements Regarding Endurance and Margin Testing," was to gather information to assess the adequacy of nuclear power plant EDG endurance and margin testing as prescribed in plant-specific TS. The inspectors reviewed emergency diesel generator ratings, design basis event load calculations, surveillance testing requirements, and emergency diesel generator vendor's specifications and gathered information in accordance with TI 2515/176.

The inspector assessment and information gathered while completing this TI was discussed with licensee personnel. This information was forwarded on to the Office of Nuclear Reactor Regulation for further review and evaluation.

b. Findings No findings of significance were identified.

\

40A6 Meetings. Including Exit Exit Meeting Summary On January 9, 2009, the resident inspectors presented the inspection results to Mr. C. Mudrick and other members of his staff. The inspectors confirmed that proprietary information was not included in the inspection report.

ATTACHMENT: SUPPLEMENTAL INFORMATION Enclosure

A-1 SUPPLEMENTAL INFORMATION KEY POINTS OF CONTACT Exelon Generation Company C. Mudrick, Site Vice President E. Callan, Plant Manager D. DiCello, Manager, Radiation Protection R. Dickinson, Director, Engineering P. Gardner, Director, Operations R. Kreider, Manager, Regulatory Assurance M. Jesse, Manager, Nuclear Oversight S. Bobyock, Manager, Plant Engineering D. Palena, Manager, Electrical Engineering Systems E. Dennin, Shift Operations Superintendent C. Gray, Manager, Radiological Engineering R. Harding, Engineer, Regulatory Assurance J. Berg, System Manager, HPCI J. George, System Manager, RHR M. Gift, System Manager, Radiation Monitoring Systems L. Lail, System Manager, EDG R. Gosby, Radiation Protection Technician, Instrumentation D. Malinowski, Simulator Instructor J. Sprucinski, Senior Radiation Protection Technician D. Dicello, Manager Radiation Protection R. Harding, Regulatory Assurance J. Risteter, Radiation Protection Manager D. Wahl, Environmental Scientist C. Rich, Manager of Nuclear Training J. Hunter, Operations Training Manager D. Malinowski, Supervisor Requalification Training W. Ward, Exam Developer D. Monahan, Simulator Operator/Instructor R. Harding, Licensing J. Mihm, Instructor/Evaluator S. Cohen, Instructor/Evaluator LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened 05000352, 353/2008005-01 URI Changes to Technical Specification 3.8.1 Bases (Section 1R18.2)

Closed T12515/176 TI Emergency Diesel Generator Technical Specification Surveillance Requirements Regarding Endurance and Margin Testing (Section 40A5.2)

Attachment

A-2 Opened and Closed 05000353/2008005-02 NCV Inadequate Post-Maintenance Test following Containment Isolation System Relay Replacement*

(Section 1R19)

Discussed *

• None LIST OF DOCUMENTS REVIEWED Section 1R01: Adverse Weather Protection.

Procedures GP-7, Cold weather preparation and operation, Revision 37 1S08.8A(COL-2), Lineup for #1 CST and associated pipe freeze protection, Revision 4 S08.8.A, RWST, #1 and #2 CST Freeze Protection, Revision 10 Issue Reports and Action Requests IR 835716, Standby liquid control heat trace trouble IR 822546, Unit 2 A Standby liquid control pump suction low temperature IR 831301, NOS identified weaknesses in winter readiness program Miscellaneous \

Maintenance Manpower Planning System Tier 2 AR's, Winter Readiness R1089680, Plant Heating and Auxiliary Steam System Section 1R04: Equipment Aliqnment Procedures HPCI System health Overview (LlM-01) 1555.1.A Equipment Alignment for Automatic Operation of HPCI System, Revision 25 Technical Specification % 5.1 ECCS Operating, Amendment 192 UFSAR 6.3.2.2.1., High Pressure Coolant Injection System, Revision 14 2S92.1.N (COL-1), Equipment Alignment for 2A Diesel Generator operation, Rev. 23 Issue Reports and Action Requests IR 202873, Update Reference Operability Tech Evaluation for EDG Lube Oil 2592.1N (CoI1),

Equipment Alignment for 2A Diesel Generator Operation, Revision 23 IR 837503, Jacket water coolant pump has oil leak Miscellaneous M-51, Piping and Instrumentation Drawing RHR System 1 S51.1.A (COL-2), Equipment Alignment for Automatic Orientation of the RHR System in the LPCI mode - B subsystem, Revision 2 Section 1 R05: Fire Protection Procedures Pre-fire Plant F-R-108, Fire Area 33 Attachment

A-3 Pre-fire Plant F-R-109, Fire Area 34 Pre-fire Plant F-R-179, Fire Area 56 Pre-fire Plant F-R-180, Fire Area 57 Pre-fire Plant F-R-475, Fire Area 68 Issue Reports and Action Requests IR 788507, AG-CG-200 Revision for IN 2007-26 NRC IN 2007-26, Combustibility of Epoxy Floor Coatings at Nuclear Power Plants Section 1R07: Heat Sink Performance Procedures RT-1-011-390-0, EDW Room Cooler Heat Transfer Performance Calculation Test, Revision 005 RT-2-011-394-1, 1EV211 Core Spray Room Cooler Air to Water Heat Transfer Test, Revision 7 RT-2-011-391-2, 2BV210 R, RHR Room Cooler Air to Water Heat Transfer Test, Revision 7 Issue Reports IR 845146, 1E CS Room cooler heat transfer performance IR 847711, Core spray unit cooler heat transfer test EOC IR 849014, Impact review for CS room heat load change not performed Section 1R11: Licensed Operator Regualification Program Issue Reports IR 814656, Level 3 Procedure Non-compliance IR 732554, Exceeded TS required Cool down Rate IR 750227, SRM Inoperative While CR Moved Training and Other Procedures TQA-M-150, Rev 1, Operator Training Programs N-LP-PIMS-LREACTQM, Rev 13, Activation and Reactivation Guide for SRO and RO OP-M-105-102, Rev 9, NRC Active License Maintenance HR-M-07-101, NRC Licensed Operator Medical Examination OP-M-105-101, Administrative Process for NRC License and Medical Requirements Scenario Tests LSES-2005, Rev 6 LSES-2006, Rev. 6 LSES-3007, Rev 6 LSES-5002, Rev 3 LSES-2007, Rev 8 LSES-5005, Rev 5 LSES-2004, Rev 6 LSES-3003, Rev 8 Job Performance Measures LLOJPM0522 LLOJPM0049 LLOJPM0031 LLOJPM0107 LLOJPM0129 LLOJPM0525 LLOJPM0111 LLOJPM0522 LLOJPM0200 LLOJPM0210 LLOJPM0207 LLOJPM0262 LLOJPM0261 LLOJPM0211 LLOJPM0097 LLOJPM0098 LLOJPM0099 Attachment

A-4 Simulator Documents TQ-AA-302 rev 7 (Simulator Testing and Documentation)

. TQ-AA-303 rev 5 (Controlling Simulator Core Updates and Thermal-Hydraulic Model Updates)

Listing of SWRs Generated Since October 2007 Listing of all Simulator Tests Performed in 2007 and 2008 Transient Tests:

• Plant Transient Review (PTR) PTR040605 Loss of the 20 Bus (Offsite bus) - compared actual event to simulator PTR010408 Plant Event Review - Feedwater Heater 6A Removal from Service PTR091805 Plant Transient Review - Trip of 2C Condensate Pump on 9/18/2005 Transient Test 7.08 Maximum Size Reactor Coolant System Rupture Combined with a Loss of All Offsite Power Transient Test 7.02 Trip of All Feedwater Pumps MalfunctionlTransient Tests:

5.02A Recirc Loop A Rupture at 100 percent Severity Core Performance Tests (BOC)

ST-6-107-884-1 Neutron Monitoring System Overlap Verification on Startup ST-3-107-870-1 Shutdown Margin Determination ST-3-107-800-1 Control Rod Density Comparison (Reactivity Anomalies)

Other Documents Reviewed RT 000-994-0, Rev 12, Verification of Operator Qualifications \

Curriculum Review Committee 4th Quarter Meeting Minutes, November 3, 2008 IR 847625 Section 1R12: Maintenance Effectiveness Procedures EPRI Technical Report 1011218, Basler SER-CB Voltage Regulators for Emergency Diesel Generators, Final Report, December 2005 Issue Reports IR 829844, A Cont. Enc!. Chiller Tripped IR 348392, 2 A Drywell Chiller Tripping on Low from Temp IR 755784, High Condenser Trip of B Control Chiller IR 798868, OA MCR Chiller Tripped on Low Refrigerant Temp IR 801316, B MCR Chiller Tripping Upon Start-Up IR 808020, OB-K112 Trips on Low From Temp IR 829990, Chiller Tripped on Low Refrigerant Temp IR 844630, PAR Meeting Identifies Trend in Chiller Performance IR 836393, NRC Concern - Maintenance rule effectiveness for RRCS IR 834878, A IR was misclassified as not a functional failure IR 836102, Unit 2, Div 2 RRCS Test Fault IR 620856, Unit 2 Automatic Scram IR 792084, Unit 2 Div II RRCS test fault IR 585323, Received Div 2 RRCS out of service alarm IR 602178, FHLOI found defective during PM IR 603069, Defective card found during RRCS card inspection PM Attachment

A-5 IR 608695, Div II RRCS trouble not resetting IR 544186, Div I RRCS out of service alarm Unit 2 IR 646248, Emergent PRA - UJ1 RRCS self test fault and will not reset IR 718479, Div I RRCS alarms received in the MCR IR 735773, Div II RRCS trouble Section 1 R13: Maintenance Risk Assessments and Emergent Work Control Procedures Technical evaluation 839237-05, Determine Availability of Unit 1 HPCI during Replacement of Square Root Converter Operational Technical Decision Making Issue 55-08-001, Unit 1 HPCI Flaw Circuit Repair during Offsite 10 Bus System Outage Section 1R18: Plant Modifications Procedures Engineering Change LG-99-00682, Limerick Technical Specification Bases Changes to %.8, Offsite Power Engineering Change Request LG-06-00227, Vibration Monitoring for HV-51-2F050A(B),

Revision 1 CC-AA-102, Design Input and Configuration for Change Impact Screening, Revision 10 CC-AA-112, Temporary Configuration Changes, Revision 10 Tech Spec 3/4.5.1 ECCS Operating, Amendment 192 Miscellaneous Drawing #051-01, Revision 1 UFSAR Section 6.3, Emergency Core Cooling Systems, Revision 14 Temporary Change 08-05-71-0 for ST-6-011-232-0 Section 1R19: Post Maintenance Testing Procedures ST-6-092-933-1, D13 Diesel Generator Governor and Voltage Regulator Post Maintenance Testing, Rev. 6, completed 11-12-08 AR 1684886, Evaluation 01, Evaluate PMT Requirement for Diaphragm Change Out Section 1 R22: Surveillance Testing Procedures CY-LG-120-105, Obtaining Samples from and Operation of the Reactor Enclosure Sample Station, Revision 7 ST-5-041-800-1, Revision 19, Reactor Coolant Chemistry ST-6-107-596-2, Drywell Floor Drain Sump/Equipment Drain Tank Surveillance Log, Revision 22 Issue Reports and Action Requests IR 826190, Wrong Flow Rate Listed in ST-6-011-232-0 IR 834490, ESW flow rates in most recent P,V&F not proven Attachment

A-6 Section 40A1: Performance Indicator (PI) Verification Procedures CY-LG-120-105; Obtaining Samples from and Operation of the Reactor Enclosure Sample Station, Revision 7 CY-LG-120-110; Chemistry Sampling and Analysis, Revision 9 CY-LG-120-601; Determination of Dose Equivalent 1-131, Revision 2

• ER-AB-331-1006; BWR RCS Leakage Monitoring and Action Plan, Revision 1 LS-AA-2001; Collecting and Reporting of NRC Performance Indicator Data, Revision 11 LS-AA-2100, Monthly Data Elements for NRC Reactor Coolant (RCS) Leakage, Revision 5 LS-AA-2200; Mitigating System Performance Index Data Acquisition and Reporting, Revision 2 ST-5-041-BB5-1; Dose Equivalent 1-131 Determination, Revision 17 ST-5-041-BB5-2; Dose Equivalent 1-131 Determination, Revision 13 ST-6-107-596-1, Drywell Floor Drain Sump/Equipment Drain Tank Surveillance Log/OPCON 1,2,3, Revision 19 ST-6-107-596-2, Drywell Floor Drain Sump/Equipment Drain Tank Surveillance Log/OPCON 1,2,3, Revision 22 Issue Reports and Action Requests IR 707262, June 2007 ESW MSPI Unavailability Data Incorrect IR 73270B, RHRSW System MSPI Data Errors Miscellaneous Main Control Room Operator Logs 10/1/2007-10/5/200B NEI 99-02; Regulatory Assessment Performance Indicator Guideline, Revision 5

\

Reactor Oversight Program MSPI Basis Document, Limerick Generating Station, Revision 1 U1 MSPI Cooling Water System Unavailability Index, Feb & Aug 200B U2 MSPI Cooling Water System Unavailability Index, Feb & Aug 200B U1 MSPI Cooling Water System Unreliability Index, Feb & Aug 200B U2 MSPI Cooling Water System Unreliability Index, Feb & Aug 200B Procedures ST-5-061-B10-0, Rev. 22 Batch Liquid Waste Releases Monthly Composite Analysis and Liquid Release Dose Calculations and Setpoint Determination for RISH-063-0K604 ST-5-076-B26-0, Rev. B Monthly Gaseous Release Dose Calculations LS-AA-2150, Rev. 5 Monthly Data Elements for RETS/ODCM Radiological Effluent Occurrences LS-AA-2140, Rev. 4 Monthly Data Elements for NRC Occupational Exposure Control Effectiveness Section 40A2: Identification and Resolution of Problems Issue Reports and Action Requests IR 654041, Dual Indication for HV-51-2F024A During Stroke Close IR 771716, HV-51-2F024A Diagnostic Test Rescheduled IR 774661, Inspect Valve Internals No Later Than 1R13 IR 774B74, Inspect Valve Internals No Later Than 2R11 Attachment

A-7 IR 766331-03, Evaluation of HV-051-2F024A with Degraded Internals AR 1625952, 2A RHR PP. Full Flow Test Return Valve.

LIST OF ACRONYMS ADAMS Agencywide Documents Access Management System AR action request CAP Corrective Action Program CCM capacity control module CFR Code of Federal Regulations CNO Chief Nuclear Officer ECR engineering change request EDG emergency diesel generator ESW emergency service water FF functional failure HPCI high pressure coolant injection IMC Inspection Manual Chapter IR issue report JPM job performance measure LCO limiting condition operation MCR main control room MPFF maintenance preventable functional failure NCV non-cited violation NEI Nuclear Energy Institute NRC Nuclear Regulatory Commission NSSSS nuclear steam supply shutoff system OSS out of service P&ID piping and instrumentation drawing PARS Publicly Available Records PI performance indicator PMT post-maintenance test RCIC reactor core isolation cooling RG Regulatory Guide RHR residual heat removal RRCS redundant reactivity control system RTP rated thermal power SDP significance determination process SR surveillance requirement SSC structure, system, component ST surveillance test SWR simulator work requests TI temporary instruction TS technical specification UFSAR updated final safety analysis report URI unresolved item WO work order Attachment

NUREG-0800 U.S. NUCLEAR REGULATORY COMMISSION STANDARD REVIEW PLAN 9.5.1.1 FIRE PROTECTION PROGRAM REVIEW RESPONSIBILITIES Primary - Organization responsible for the review of fire protection Secondary - None I. AREAS OF REVIEW The purpose of the fire protection program (FPP) is to provide assurance, through a defense-in-depth (DID) philosophy, that the Commission's fire protection objectives are satisfied. These objectives are: 1) to prevent fires from starting; 2) to detect rapidly, control, and extinguish promptly those fires that do occur; and 3) to provide protection for structures, systems and components (SSCs) important to safety so that a fire that is not promptly extinguished by the fire suppression activities will not prevent the safe shutdown of the plant. In addition, fire protection systems must be designed such that their failure or inadvertent operation does not adversely impact the ability of the SSCs important to safety to perform their safety functions. The FPP fo~

a nuclear power plant licensed to operate generally consists of the following elements:

Revision 0 - February 2009 USNRC STANDARD REVIEW PLAN This Standard Review Plan I I I II c I how the criteria I an acceptable method of complying with the NRC regulations.

The standard review plan sections are numbered in accordance with corresponding sections in Regulatory Guide 1. 70, ~Standard Fannat and Content of Safety Analysis Reports for Nuclear Power Plants (LWR Edition}.H Not all sections of Regulatory Guide 1.70 have a corresponding review plan section. The SRP sections applicable to a combined license application for a new light-water reactor (LWR) are based on RegulatOl), Guide 1.206, "Combined License Applications for Nuclear Power Plants (LWR Edition)."

These documents are made available to the public as part of the NRC's policy to inform the nuclear industry and the general public of regulatory procedures and policies. Individual sections of NUREG-0800 will be revised periodically, as appropriate, to accommodate comments and to reflect new information and experience. Comments may be submitted electronically by email to NRR_SRP@nrc.gov.

Requests for single copies of SRP sections (which may be reproduced) should be made to the U.S. Nuclear Regulatory Commission, Washington, DC 20555, Attention: Reproduction and Distribution Services Section, or by fax to (301) 415-2289; or by email to DISTR1BUTION@nrc.gov. Electronic copies of this section are available through the NRC's public Web site at http://www.nrc.gov/reading-rm/doc-collections/nuregs/staff/srOBOOl, or in the NRC's Agencywide Documents Access and Management System (ADAMS), at http://www.nrc.gov/reading-rm/adams.html,underAccession # ML090510170.

Enclosure 12

• comprehensive identification and analysis of fire and explosion hazards

• organization and staff positions responsible for management and implementation of the FPP

• fire prevention program consisting of administrative policy, procedures, and practices for training of general plant personnel; control of fire hazards; inspection, testing and maintenance of fire protection systems and features; control of plant design and modification; control of fire system outages and impairments; and FPP quality assurance

• automatic fire detection, alarm, and suppression systems, including fire water supply and distribution systems

• manual suppression capability including portable fire extinguishers, standpipes, hydrants, hose stations, fire department connections, fire brigade organization, training, qualification, equipment, and drills; emergency plans and procedures; and, if applicable, offsite mutual aid capabilities

• building design for fire protection including layout of fire areas, fire barrier design and qualification testing, interior finish, electrical system design, ventilation system design, drainage systems, and other systems and features for minimizing the threat of fire

• post-fire safe-shutdown analysis and procedures that demonstrate that the plant can achieve and maintain safe shutdown in the event of a fire

• probabilistic risk assessment (PRA) that identifies relative fire risks and vulnerabilities The specific areas of the FPP to be reviewed will vary depending on the type and scope of the applicant's or licensee's submittal. This Standard Review Plan (SRP) can be applied in the review of the FPP for the following submittals:

• applications for new reactor design certifications (DCs)

• applications for new reactor combined licenses (COls)

• applications to shut down and decommission a licensed plant

• applications for license renewal

• license amendment requests for power uprates

• licensee requests for exemptions and other license amendments that impact FPPs

• other FPP-related submittals, such as fire PRAs SRP Section 9.5.1.1 focuses on deterministic FPPs. This SRP section is not intended to be the primary review guidance document for plants that have adopted a risk-informed, performance-based.FPP in accordance with Ti.tle 10 of the Code of Federal Regulations, 50.48(c) (10 CFR 50:48(c>> and National Fire Protection Association (NFPA) Standard NFPA 805. The primary review guidance document forNFPA 805 plants will be developed in the future. In the interim, this SRP will be used as appropriate for applications for plants that adopt a performance-based FPP in accordance with 10 CFR 50.48(c). Otherwise, unless specifically noted, the review guidance in this SRP section is applicable to the FPP for both existing and new reactor plants.

The staff reviews the FPP described in the licensee's or applicant's submittal with reference to the Acceptance Criteria in this SRP. Specifically, the staff reviews the following to the extent appropriate for the type and scope of the licensee submittals:

1. FPP administration with respect to fire protection organization; administrative policies; fire prevention controls; applicable administrative, operations, maintenance and emergency procedures; quality assurance; access to and egress from fire areas; fire brigade capability; and emergency response capability.2. Evaluation of the potential fire hazards for areas containing equipment important to safety throughout the plant, for 9.5.1.1-2 Revision 0 - February 2009

the effect of postulated fires and explosions relative to maintaining the ability to perform safe-shutdown functions, and for minimizing radioactive releases to the environment.

3. Plant layout, access and egress routes with respect to: 1) firefighting and local operator manual actions, 2) facility arrangements, and 3) structural design features that provide separation or isolation of redundant systems important to safety.

4. Selection and design of fire detection, alarm, control and suppression systems on the basis of the fire hazards analysis; of design, testing, qualification, and maintenance of fire barriers, including penetration seals; of use of noncombustible materials; and of design of floor drains, ventilation, emergency lighting and communication systems.

5. The fire protection system piping and instrumentation diagrams CP&IDs), including with respect to redundancy of equipment and with respect to the fire protection design criteria and failure modes and effects analysis, including the potential effects of inadvertent discharge or failure of fire protection systems on SSCs important to safety.

6. On multiple unit sites, fire protection and control proviSions during construction. shutdown or decommissioning of the adjacent units, in order to verify that the integrity and operability of the shared fire protection systems are maintained and that fire hazards associated with one unit will not have an adverse affect on the adjacent unit.

7. For operating plants and new design applications, post-fire safe-shutdown analysis, including the list of systems and components needed to provide post-fire safe-shutdown capability; the arrangement of the systems and components within the plant fire areas; the separation between redundant safe-shutdown systems and components; the fire protection for safe-shutdown systems and components; and potential interactions between non-safety systems, fire protection systems, and systems important to safety for potential adverse effects on the safe-shutdown capability. New reactor designs must also meet the Commission'S enhanced fire protection criteria as described in Appendix A to this SRP section.

8. FPP for shutdown and decommissioned reactors as part of the overall review of the decommissioning plans and activities .under 10 CFR 50.82. The staff reviews the fire hazards analysis, fire protection systems and features, and other measures necessary to protect against the release of radioactive material as a result of fire adversely impacting spent fuel storage or radioactive wastes from plant decommissioning, dismantlement, or demolition. The Office of Nuclear Reactor Regulation has review responsibility during the initial stages of decommissioning. The Office of Nuclear Material Safety and Safeguards, Division of Waste Management and Environmental Protection, DecommisSioning Directorate, oversees the decommissioning program after the fuel has been removed from the plant spent fuel pool (SFP), including approval of license termination when decommissioning activities are successfully completed.

9. Inspections. Tests. Analyses. and Acceptance Criteria (lTAAC). For DC and COL reviews, the staff reviews the applicant's proposed ITAAC associated with the SSCs related to this SRP section in accordance with SRP Section 14.3, "Inspections, Tests, Analyses, and Acceptance Criteria." The staff recognizes that the review of ITAAC cannot be completed until after the rest of this portion ofthe application has been reviewed against acceptance criteria contained in this SRP section. Furthermore, the 9.5.1.1-3 Revision 0 - February 2009

staff reviews the ITAAC to ensure that all SSCs in this area of review are identified and addressed as appropriate in accordance with SRP Section 14.3.

10. COL Action Items and Certification Requirements and Restrictions. For a DC application, the review will also address COL action items and requirements and restrictions (e.g., interface requirements and site parameters).

For a COL application referencing a DC, a COL applicant must address COL action items (referred to as COL license information in certain DCs) included in the referenced DC. Additionally, a COL applicant must address requirements and restrictions (e.g.,

interface requirements and site parameters) included in the referenced DC.

11. Operational Program Description and Implementation, For a COL application, the staff reviews the FPP description and the proposed implementation milestones. The staff also reviews final safety analysis report (FSAR) Table 13.x to ensure that the FPP and associated milestones are included. Specific to this SRP section is the FPP based on the requirements of 10 CFR 50.48.

12. RegulatorvTreatment of Non-Safetv Systems. For DC and COL reviews of reactor designs that rely on the fire protection system to provide backup to a safe shutdown system, the staff reviews the applicant's commitments for regulatory treatment of non-safety systems (RTNSS).

Review Interfaces Other SRP sections interface with this section as follows:

1. Fire PRAs are reviewed as part of SRP Section 19.0, "Probabilistic Risk Assessment."

The organization responsible for review of the PRA may consult the organization responsible for fire protection.

2. Guidance for review of plant features that ensure safe shutdown in the event of an intentional attempt to damage plant SSCs (e.g., terrorist attack) is provided in SRP Section 13.6.

3. For COL reviews of operational programs, the review of the applicant's implementation plan is performed under SRP Section 13.4, "Operational Programs."

The specific acceptance criteria and review procedures are contained in the referenced SRP sections.

II. ACCEPTANCE CRITERIA The applicability of the following requirements and acceptance criteria in the conduct of the review is dependent on the type and scope of the submittal. For operating reactors, power uprates and license renewals, the eXisting plant licensing basis, and specifically the fire protection license condition, establishes the applicability of the acceptance criteria listed below.

For shut down and decommissioned reactors, only a portion of the criteria is applicable, and the specific criteria of Regulatory Guide (RG) 1.191, "Fire Protection Program for Nuclear Power 9.5.1.1-4 Revision 0 - February 2009

Plants During Decommissioning and Permanent Shutdown," should provide the basis for the review. For new applications, the criteria in paragraphs 1-6 below are applicable as modified by other relevant criteria, including the enhanced fire protection criteria of SECY 90-016 and SECY 93-087, as well as the passive plant safe-shutdown criteria of SECY 94-084.

The acceptance criteria included in previous revisions of this SRP section as Branch Technical Position (BTP) SI<'LB 9.5.-1 have been removed and have been incorporated in Revision 1 of RG 1.189, "Fire Protection for Nuclear Power Plants."

Requirements Acceptance criteria are based on meeting the relevant requirements of the following Commission regulations:

1. 10 CFR 50.48, "Fire protection," which requires that operating nuclear power plants have a fire protection plan that satisfies General Design Criterion (GDC) 3 and also provides general requirements regarding the content of the fire protection plan and the applicability of 10 CFR Part 50, Appendix R, "Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1, 1979."

2. 10 CFR 50.48(f) establishes the criteria for a fire protection plan for those plants that have submitted the certifications required for license termination under 10 CFR 50.82(a)(1).

3. 10 CFR Part 50, Appendix A, GDC 3, "Fire Protection," establishes the criteria for the fire and explosibn protection of SSCs important to safety. GDC 3 also establishes the criteria for fire detection and firefig hting systems and for the use of noncombustible and heat-resistant materials throughout the unit.

4. 10 CFR Part 50, Appendix A, GDC 5, "Sharing of Structures, Systems, and Components," as it applies to shared fire protection systems and potential fire impacts on shared SSCs important to safety.

5. 10 CFR Part 50, Appendix A, GDC 19, "Control Room," as it applies to providing the capability both inside and outside the control room to operate plant systems necessary to achieve and maintain safe-shutdown conditions.

6. 10 CFR Part 50, Appendix A, GDC 23, "Protection System Failure Modes," as it applies to safe-failure states of the protection system when exposed to adverse conditions associated with fire events or inadvertent operation of fire protection systems.

7. 10 CFR Part 50, Appendix R, "Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1, 1979," which establishes the FPP requirements for nuclear power plants operating prior to January 1, 1979, subject to the proVisions in 10 CFR 50.48(b). Appendix R establishes, along with other fire protection requirements, the requirement to demonstrate that one success path of SSCs necessary to achieve and maintain safe shutdown of the reactor is protected from the effects of fire. The substantive provisions of Appendix R, or portions thereof, may apply to plants licensed to 9.5.1.1-5 Revision 0 - February 2009

operate after January 1, 1979, to the extent incorporated in or provided for in the fire protection licensing basis for the individual plants.

8. 10 CFR Part 52, "Early Site Permits; Standard Design Certifications; and Combined Licenses for Nuclear Power Plants," which establishes regulatory requirements applicable to new reactors.

9. 10 CFR 52.47(b)(1), which requires that a DC application contain the proposed ITAAC that are necessary and sufficient to provide reasonable assurance that, if the inspections, tests, and analyses are performed and the acceptance criteria met, a plant that incorporates the DC is built and will operate in accordance with the DC, the provisions of the Atomic Energy Act (AEA), and the NRC's regulations;

10. 10 CFR 52.80(a), which requires that a COL application contain the proposed inspections, tests, and analyses, including those applicable to emergency planning, that the licensee shall perform, and the acceptance criteria that are necessary and sufficient to provide reasonable assurance that, if the inspections, tests, and analyses are performed and the acceptance criteria met, the facility has been constructed and will operate in conformity with the COL, the provisions of the AEA, and the NRC's regulations.

11. 10 CFR Part 72, "Licensing Requirements for the Independent Storage of Spent Nuclear Fuel, High-Level Radioactive Waste, and Reactor-Related Greater than Class C Waste,"

which establishes regulatory requirements applicable to spent nuclear fuel and waste storage.

SRP Acceptance Criteria Specific SRP acceptance criteria acceptable to meet the relevant requirements of the NRC's regulations identified above are as follows for the review described in this SRP section. The SRP is not a substitute for the NRC's regulations, and compliance with it is not required.

However, an applicant is required to identify differences between the design features, analytical techniques, and procedural measures proposed for its facility and the SRP acceptance criteria and evaluate how the proposed alternatives to the SRP acceptance criteria provide acceptable methods of compliance with the NRC regulations.

1. RG 1.174, Revision 1, "An Approach for Using Probabilistic Risk Assessment In Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," as it applies to the use of PRA in support of changes to the fire protection licensing basis for nuclear power plants. Appropriate techniques for performing a Fire PRA are presented in NUREG/CR-6850 (EPRI TR-1 011989), "EPRI/NRC-RES Fire PRA Methodology for Nuclear Power Facilities."

2. RG 1.188, Revision 1, "Standard Format and Content for Applications to Renew Nuclear Power Plant Operating Licenses," as it applies to FPP considerations for license renewal such as equipment aging issues. This RG endorses the guidance in Nuclear Energy Institute (NEI) document, NEI 95-10, Revision 0, "Industry Guideline for Implementing the Requirements of 10 CFR Part 54 - The License Renewal Rule."

9.5.1.1-6 Revision 0 - February 2009

3. RG 1.189, Revision 1, "Fire Protection for Nuclear Power Plants," which provides comprehensive staff positions and guidelines on fire protection for nuclear power plants.

4. RG 1.191, "Fire Protection Program for Nuclear Power Plants During Decommissioning and Permanent Shutdown," which establishes the fire protection objectives and staff pOSitions for implementing fire protection for those nuclear power plants that have submitted the necessary certifications for license termination.under 10 CFR Part 50.82(a).

5. RG 1.206, "Combined License Applications for Nuclear Power Plants (LWR Edition)," as it applies to the FPP of any new reactor COL application submitted in accordance with 10 CFR Part 52.

6. Enhanced fire protection criteria for new reactor designs as documented in SECY 90-016, SECY 93-087, and SECY 94-084. SECY 90-016 established enhanced fire protection criteria for evolutionary light-water reactors (LWRs). SECY 93-087 recommended that the enhanced criteria be extended to include passive reactor designs.

SECY 90 016 and SECY 93-087 were approved by the Commission in staff requirements memoranda. SECY 94-084, in part, establishes criteria defining safe-shutdown conditions for passive LWR designs.

7. For COL reviews, the description of the operational program and proposed implementation milestone(s) for the FPP are reviewed in accordance with 10 CFR 50.48.

The operational program for fire protection should be fully implemented prior to fuel receipt at the plant site.

1 III. REVIEW PROCEDURES The reviewer will select material from the procedures described below, as may be appropriate for a particular case.

These review procedures are based on the identified SRP acceptance criteria. For deviations from these acceptance criteria, the staff should review the applicant's evaluation of how the proposed alternatives provide an acceptable method of complying with the relevant NRC requirements identified in Subsection II.

For each type of submittal, the staff will conduct the review as follows:

1. New Reactor Applications

a. For applications submitted in accordance with 10 CFR Part 50, the staff reviews the preliminary safety analysis report (PSAR) and the FPP in the FSAR. All applicable areas of review listed in Section I should be included in the reView for a new reactor application.

Reviews that cannot be performed adequately at the PSAR stage due to incomplete development of the FPP should be performed at the FSAR stage of the license application. See Appendix A to this SRP section for additional information.

b. For review of a DC application, the reviewer should follow the above procedures to verify that the design, including requirements and restrictions (e.g., interface requirements and site parameters), set forth in the FSAR meets the acceptance criteria. DCs have referred 9.5.1.1-7 Revision 0 - February 2009

to the FSAR as the design control document. The reviewer should also consider the appropriateness of identified COL action items. The reviewer may identify additional COL action items; however, to ensure these COL action items are addressed during a COL application, they should be added to the DC FSAR.

For review of a COL application, the scope of the review is dependent on whether the COL applicant references a DC, an early site permit or other NRC approvals (e.g.,

manufacturing license, site suitability report or topical report).

For review of both DC and COL applications, SRP Section 14.3 should be followed for the review of ITMC. The review of ITMC cannot be completed until after the completion of this section.

c. For all submittals, the staff verifies that the FPP is fully described and that implementation milestones have been identified. The staff verifies that the program and implementation milestones are included in FSAR Table 13.x.

The staff will verify the satisfactory implementation of the programmatic aspects of the FPP by inspection in accordance with NRC Inspection Manual Chapter IMC-2504, "Construction Inspection Program - Non-ITMC Inspections." The staff ensures that the program and associated implementation milestone(s) are included within the license condition on operational programs and implementation. The satisfactory implementation of other aspects of the FPP will be verified by inspection in accordance with NRC Inspection Manual Chapter IMC-2503, "Inspections, Tests, Analyses, and Acceptance Criteria (ITMC)."

d. The staff provides any necessary support to the organization reviewing fire PRAs in support of new plant DC applications and COL applications.

2. License Renewal The staff reviews applications for license renewal to ensure that fire protection SSCs required for compliance with 10 CFR 50.48 are included within the scope of license renewal in accordance with 10 CFR 54.4(a). For those SSCs identified as being in scope, the staff identifies those components that are subject to an aging management review in accordance with 10 CFR 54.21 (a)(1). Appendix B of this SRP provides additional guidance for such a review.

The staff provides any necessary support to the primary reviewing office for the review of fire PRAs in support of license amendment requests for plant life extension.

3. Power Uprates The staff reviews license amendment requests for power uprate to ensure that the changes associated with the power uprate do not adversely affect the ability to achieve and maintain safe shutdown following a fire and that regulatory requirements for fire protection continue to be met.

Changes to the plant's power level must be requested and approved via a license amendment, pursuant to 10 CFR 50.90, 50.91, and 50.92. Appendix D of this SRP provides additional guidance for such a review. The staff provides any necessary support to the primary reviewing office for the review of fire PRAs in support of power uprate license amendment requests.

9.5.1.1-8 Revision 0 - February 2009

4. License Termination The staff reviews the FPP for shutdown and decommissioning operations for those plants that have submitted the necessary certifications required by 10 CFR 50.82(a)(1). RG 1.191 provides additional guidance for review of FPPs for shutdown and decommissioning of nuclear power plants.

5. . FPP Exemptions - Existing Plants The staff reviews submitted requests for exemption from regulatory requirements applicable to the FPP in accordance with 10 CFR 50.12. The staff reviews the technical justification for the alternative approach and determines whether an exemption is appropriate under the 10 CFR 50.12 guidelines. RG 1.189 provides detailed criteria and guidelines for review of FPP exemption requests, including general conditions for acceptance.

Where fire modeling or fire probabilistic risk assessment methodologies are used as a basis for an exemption request, the review of the exemption will consider the guidance and acceptance criteria for fire modeling provided in RG 1.189, as well as the guidance provided in this SRP, draft NUREG-1824/EPRI 1011999, "Verification and Validation of Selected Fire Models for Nuclear Power Plant Applications," and NUREG/CR-6850 (EPRI TR-1011989).

6. FPP Exemptions and Departures - New Reactor Plants The staff reviews exemptions to an approved DC for a new reactor in accordance with the provisions of 10 CFR 52.7 (which references the same criteria for the granting of exemptions that are setforth in 10 CFR 50.12). 1 A departure is a plant-specific "deviation" from design information in a standard DC. Departures from the referenced DC for the FPP should be discussed in the fire protection section of the COL application. Sufficient information should be provided for the staff to resolve all safety and security issues in its review of the departure. A departure requires the applicant to obtain an exemption from the referenced DC if the proposed departure is inconsistent with one or more of the Commission's regulations.

7. FPP License Amendments - New Reactors The staff reviews license amendments for modifications to, additions to, or deletions from the terms of a new reactor COL, including the ITAAC, in accordance with 10 CFR 52.97(b)(2).

IV. EVALUATION FINDINGS The reviewer verifies that the applicant has provided sufficient information and that the review and calculations (if applicable) support conclusions of the following type to be included in the staff's safety evaluation report (SER). The reviewer also states the bases for those conclusions.

1. New Reactor DCs and COL Applications The staff concludes that the applicant's FPP design criteria and associated implementation are acceptable and meet the applicable requirements of 10 CFR Part 50 9.5.1.1-9 Revision 0 - February 2009

and Part 52, and are consistent with Commission policy contained in SECY 90-016, SECY 93-087, and SECY 94-084 (plants with passive safe-shutdown), as well as other applicable acceptance criteria (staff should specify the applicable criteria depending on the type and scope of review). As described above, the staff finds that the applicant has met the guidelines of the applicable RGs and related industry standards.

The applicant has demonstrated that safe shutdown can be achieved even assuming that all equipment in anyone fire area (excluding the control room and reactor containment) will be rendered inoperable by fire and that re-entry into the fire area for repairs and operator actions is not possible. The applicant's design has provided an independent alternative shutdown capability that is physically and electrically independent of the control room. The applicant's design provides fire protection for redundant shutdown systems in the reactor containment building that will ensure, to the extent practicable, that one shutdown division will be free of fire damage. Additionally, the applicant's design ensures that smoke, hot gases, or fire suppressants will not migrate into other fire areas to an extent that could adversely affect safe-shutdown capabilities, including operator actions.

The applicant has demonstrated that SSCs important to safety, including SSCs that are shared among multiple units, are adequately protected from the effects of fires and explosions. The applicant's design has used noncombustible and heat resistant materials whenever practical and has provided fire detection, suppression, and firefighting capabilities of appropriate capacity and capability to minimize the adverse effects of fire on SSCs important to safety.

The staff concludes that the proposed ITAAC for the FPP provide reasonable assurance that the implementation of the FPP will be in accordance with the approved design and operational program descriptions (where applicable). The staff has included FPP and its implementation milestones within the license condition on operational program implementation.

For DC and COL reviews, the findings will also summarize the staff's evaluation of requirements and restrictions (e.g., interface requirements and site parameters) and COL action items relevant to this SRP section.

In addition, to the extent that the review is not discussed in other SER sections, the findings will summarize the staffs evaluation of the ITAAC, including design acceptance criteria, as applicable.

The staff concludes that for differences between the licensee's FPP and the SRP acceptance criteria, the proposed alternatives provide an acceptable method of complying with the NRC regulations. Sufficient information has been provided for the staff to resolve all safety and security issues in its review of any departures from the DC.

Where applicable, the staff concludes that the RTNSS process adequately identifies active non-safety related fire protection system features relied upon for DID and necessary to meet plant safety goals. The staff concludes that the regulatory requirements and acceptance criteria applicable to RTNSS have been satisfactorily addressed for these system features.

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2. License Amendments and Exemption Requests The staff concludes that the proposed exemption or amendment to the licensee's FPP is acceptable and that the FPP continues to meet the applicable requirements of 10 CFR Part 50, 10 CFR Part 52, 10 CFR Part 54, 10 CFR Part 72, and the enhanced fire protection requirements (new reactors), as well as other applicable acceptance criteria (staff should specify the applicable criteria depending on the type and scope of review). The staff has reviewed the licensee's analysis and justifications for the changes and concludes that the plant is still able to achieve and maintain safe-shutdown .

conditions and to mitigate a radiological release following a fire.

3. Shutdown/Decommissioning FPPs The staff concludes that the FPP (or related changes) for shutdown and decommissioning of the plant is acceptable and meets the requirements of 10 CFR 50.48(f) and other applicable acceptance criteria, including the guidance in RG 1.191. In meeting the acceptance criteria, the applicant for license termination has demonstrated that radioactive materials are adequately protected from the effects of fires and that potential radioactive hazards to the public, environment, and plant personnel are minimized.

V. IMPLEMENTATION The following is intended to provide guidance to applicants and licensees regarding the NRC staff's plans for using this SRP section.

The staff will use this SRP section in performing safety evaluations of DC applications, of exemption requests, license amendments, license applications, and other FPP-related submittals submitted by applicants pursuant to 10 CFR Part 50, 10 CFR Part 52, 10 CFR Part 54, or 10 CFR part 72. Except when the applicant proposes an acceptable alternative method for complying with specified portions of the Commission's regulations, the staff will use the method described herein to evaluate conformance with Commission regulations.

The provisions of this SRP section apply to reviews of applications submitted six months or more after the date of issuance of this SRP section, unless superseded by a later revision.

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VI. REFERENCES

1. 10 CFR Part 50, "Domestic Licensing of Production and Utilization Facilities."

a. 50.12, "Specific exemptions"

b. 50.34, "Contents of applications; technical information"

c. 50.48, "Fire protection"

d. 50.82, "License termination"

e. 50.90, "Application for amendment of license or construction permit"

f. 50.91, "Notice for public comment; State consultation"

g. 50.92, "Issuance of amendment"

2. 10 CFR Part 52, "Early Site Permits; Standard Design Certifications; and Combined Licences for Nuclear Power Plants."

a. 52.47, "Contents of applications."

b. 52.63, "Finality of standard design certifications"

c. 52.79, "Contents of applications; technical information"

d. 52.83, "Applicability of part 50 provisions"

e. 52.97, "Issuance of combined licenses"

3. 10 CFR Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants."

a. 54.4, "Scope"

b. 54.21, "Contents of application - technical specifications"

4. 10 CFR Part 50, Appendix A, "General Design Criteria for Nuclear Power Plants."

a. GDC 3, "Fire Protection"

b. GDC 5, "Sharing of Structures, Systems, and Components"

c. GDC 19, "Control Room"

d. GDC 23, "Protection System Failure Modes"

5. 10 CFR Part 50, Appendix R, "Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1, 1979."

6. 10 CFR Part 72, "Licensing Requirements for the Independent Storage of Spent Nuclear Fuel, High-Level Radioactive Waste, and Reactor-Related Greater than Class C Waste."

7. BTP SPLB 9.5-1 "Guidelines for Fire Protection for Nuclear Power Plants." (Formerly BTP CMEB 9.5-1)

8. BTP APCSB 9.5-1, Appendix A, "Guidelines for Fire Protection for Nuclear Power Plants Docketed Prior to July 1,1976."

9. ANS-58.23-200X, "Standard on Methodology for Fire PRA," American Nuclear Society (draft).

10. RG 1.139, "Guidance for Residual Heat Removal." (for Comment)

11. RG 1.174, Revision 1, "An Approach for Using Probabilistic Risk Assessment In Risk-Informed Decisions On Plant-Specific Changes to the Licensing Basis."

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12. RG 1.188, Revision 1, "Standard Format and Content for Applications to Renew Nuclear Power Plant Operating Licenses."

13. RG 1.189, Revision 1, "Fire Protection for Nuclear Power Plants."

14. RG 1.1l.l1, "Fire Protection Program for Nuclear Power Plants During Decommissioning and Permanent Shutdown."

15. RG 1.206, "Combined License Applications for Nuclear Power Plants (LWR Edition)."

16. NRC Inspection Manual Chapter IMC-2503, "Construction Inspection Program; Inspections of Inspections, Tests, Analyses, and Acceptance Criteria (ITMC)," issued April 25, 2006.

17. NRC Inspection Manual Chapter IMC-2503, "Construction Inspection Program; Inspections OF Inspections, Tests, Analyses, and Acceptance Criteria (lTMC)" issued April 25, 2006.

18. NUREG-0933, "A Prioritization of Generic Safety Issues."

19. NUREG-1800, Revision 1, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants."

20. NUREG-i 801, Revision 1, "Generic Aging Lessons Learned (GALL) Report."

21. NUREG-1824/EPRI 1011999, 'Verification and Validation of Selected Fire Models for Nuclear Power Plant Applications." (Draft for Comment)

22. NUREG/CR-6850 (EPRI TR-1 011989), "EPRI/NRC-RES Fire PRA Methodology for Nuclear Power Facilities."

23. SECY-90-016, "Evolutionary Light Water Reactor (LWR) Certification Issues and Their Relationship to Current Regulatory Requirements." (ML003707849)

24. SECY-93-087, "Policy, Technical, and Licensing Issues Pertaining to Evolutionary and Advanced Light-Water Reactor (ALWR) Designs." (ML003707849)

25. SECY-94-084, "Policy and Technical Issues Associated with the Regulatory Treatment of Non-Safety Systems in Passive Plant Designs." (ML003708068)

26. Staff Requirements - SECY 93-087 - "Policy, Technical, and Licensing Issues Pertaining to Evolutionary and Advanced Light-Water Reactor (ALWR) Designs," July 21, 1993.

(ML003708056)

27. Staff Requirements - SECY 90-016 - "Evolutionary Light-Water Reactor (ALWR)

Certification Issues and Their Relationship to Current Regulatory Requirements,"

June 26, 1990. (ML003707885).

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28. IN 2002-27, "Recent Fires at Commercial Nuclear Power Plants in the United States."

29. NEI95-10, Revision 0, "Industry Guide for Implementing the Requirements of

• 10 CFR Part 54 - The License Renewal Rule."

30. NFPA 804, "Standard for Fire Protection for Advanced Light Water Reactor Electric Generating Plants."

31. NFPA 805, "Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants."

PAPERWORK REDUCTION ACT STATEMENT The information collections contained in the Standard Review Plan are covered by the requirements of 10 CFR Part 50 and 10 CFR Part 52, and were approved by the Office of Management and Budget, approval number 3150-0011 and 3150-0151.

PUBLIC PROTECTION NOTIFICATION The NRC may not conduct or sponsor, and a person is not required to respond to, a request for information or an information collection requirement unless the requesting document displays a currently valid OMS control number.

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APPENDIX A Supplemental Fire Protection Review Criteria for New Reactors Unless specifically noted otherwise, the review guidance in this SRP section is applicable to the FPP for new reactor plants. This appendix provides additional guidance applicable to new reactor FPPs.

• Many of the current fire protection requirements and guidelines for operating reactors were issued after the construction permits and/or operating licenses were approved by the Commission. The backfit of these requirements and guidelines to existing plant designs created the need for considerable flexibility in the application of the regulations on a plant-by-plant basis.

For new reactor designs, fire protection requirements, including the protection of safe-shutdown capability and the prevention of radiological release, can be readily integrated in the planning and design phase for the plant.

For applications submitted in accordance with 10 CFR Part 52, design elements of the FPP are addressed in the DC process. During the DC process, action items are identified that should be addressed by the COL applicant. These commitments include action items to establish the FPP for protection of SSCs important to safety as well as the procedures, equipment, and personnel necessary to implement the program. These commitments include, but are not limited to, updating the fire hazards analysis to address final plant design and administrative program elements (e.g., licensee fire protection staffing and organization, quality assurance, procedures, fire prevention programs, and training); fire brigade and emergency response capability; the final design of fire protection systems and features; and thl design and analysis of post-fire safe-shutdown capability.

The review of COL applications should also consider the guidance to applicants provided in RG 1.206, "Combined License Applications for Nuclear Power Plants (LWR Edition)."

1. Enhanced Fire Protection Criteria Based on operational experience with existing reactors and insights from examination of internal fire events, the staff determined that fire protection for safe-shutdown capability should be enhanced for new reactor designs. The enhanced fire protection criteria were initially proposed to the Commission in SECY-90-016. This criteria was extended to the review of passive LWR designs in SECY-93-087. These criteria are as follows:

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Evolutionary advanced light-water reactor (ALWR) designers must ensure that safe shutdown can be achieved assuming that all equipment in anyone fire area (excluding the control room and reactor containment) will be rendered inoperable by fire and that re-entry into the fire area for repairs and operator actions is not possible. Because of its physical configuration, the control room is excluded from this approach, provided an independent alternative shutdown capability that is physically and electrically independent of the control room is included in the design. Evolutionary ALWRs must provide fire protection for redundant shutdown systems in the reactor containment building that will ensure, to the extent practicable, that one shutdown division will be free of fire damage. Additionally, the evolutionary ALWR designers must ensure that smoke, hot gases or the fire suppressant will not migrate into other fire areas to the extent that they could adversely affect safe-shutdown capabilities, including operator actions.

2. Passive Plant Safe-Shutdown Condition As discussed in SECY-94-084, the definitions of safe shutdown as contained in the Commission's regulations and guidelines do not address the inherent limitations of passive residual heat removal (RHR) systems.

In GDC 34 of Appendix A to 10 CFR Part 50, the NRC regulations require that the design include a RHR system to remove residual heat from the reactor core so that specified acceptable fuel design limits are not exceeded. GDC 34 further requires suitable redundancy of the components and features of the RHR system to ensure that the system safety functions can be accomplished, assuming a loss of offsite power or onsite power, coincident with a single failure. The NRC promulgated these requirements to ensure that the RHR system is available for long-term cooling to ensure a safe-shutdown state.

Post-fire safe shutdown for currently operating LWRs is defined in RG 1.189 as those conditions specified in the Technical Specifications. RG 1.139 specifies Cold Shutdown as 93.3 °C (200 OF) for pressurized-water reactor and 100°C (212 OF) for boiling-water reactors (BWRs).

Passive reactor designs are limited by the inherent ability of the passive heat removal processes and cannot reduce the temperature of the reactor coolant system below the boiling point of water for heat transfer to occur between the reactor coolant and the heat sink. The plant designs include cooling systems to bring the reactor to cold shutdown or refueling condition; however, these systems are not safety grade. These non-safety-grade systems (i.e., makeup water to the heat sink and cool-down capability) are necessary to maintain long-term cooling (i.e., beyond 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />) and should be capable of accomplishing their respective functions without damage to the fuel as demonstrated by design and analysis.

Based on the discussion and recommendations of SECY-94-084, the passive decay heat removal systems should be capable of achieving and maintaining 215.6 °C (420 OF) or below for non-Ioss-of-coolant-accidents events. This safe-shutdown condition is predicated on demonstration of acceptable passive safety system performance and the acceptable resolution of RTNSS that are necessary for long-term shutdown.

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3. Applicable Industry Codes and Standards In general, the FPP for new LWR designs should comply with the provisions specified in NFPA 804, "Fire Protection for Advanced Light Water Reactors," related to the protection of post-fire safe-shutdown capability and the mitigation of a radiological release resulting from a fire.

However, the NRC has not formally endorsed NFPA 804, and some of the guidance in the NFPA standard may conflict with regulatory requirements. Where conflicts occur, the applicable.

regulatory requirements and guidance will govern. The standards of record related to the design and installation of fire protection systems and features sufficient to satiSfy NRC requirements in all new reactor designs are those NFPA codes and standards in effect 6 months prior to the submittal of the application under 10 CFR Part 50 or 10 CFR Part 52. The codes/standards of record are governed by the DC (within 6 months of the DC document submittal date) for aspects of the FPP described in the DC. The COL should use industry codes and standards within 6 months of the COL application date for any aspects of the FPP not covered in the DC.

4. Other New Reactor Designs FPPs for proposed new non-LWR designs should meet the overall fire protection objectives outlined in RG 1.189 related to safe shutdown and radiological release, as well as the specific fire protection requirements where applicable. Fire hazards should be identified by the applicant, evaluated, and an appropriate level of protection provided to meet these objectives.

DeSign reviews and testing programs should confirm the safe-shutdown capability. SSCs important to safety should be protected in accordance with the enhanced criteria described above for new LWRs. Fire protection systems and features should be consistent with the RG 1.189 criteria to the extent a fire hazards analysis conducted by the applicant shows it to be necessary. I

5. FPP Implementation Schedule Fire protection has been identified as an "operational program" in SECY-05-0197, "Review of Operational Programs in a Combined License Application and Generic Emergency Planning Inspections, Tests, Analyses, and Acceptance Criteria." However, only those elements of the FPP that will not be fully implemented until the completion of the plant should be addressed as an operational program. These elements may include, but are not limited to, the fire brigade capability, combustible and ignition source control program, procedures and pre-fire plans, and portable extinguishing equipment. The COL application should identify the operational program aspects of the FPP and the implementation schedule for each. The staff should develop a license condition with respect to the implementation milestones. In lieu of the implementation schedule, the applicant may propose ITMC for these aspects of the program.

6. Risk-Informed Review of New Reactors Review of existing reactors' license applications included an assessment of the plants' FPPs without guidance as to the relative risk significance of one aspect of the program over another.

While the current fire protection regulations and guidance are risk-informed to a certain extent, they do not provide a basis for focusing staff resources on the most risk-significant areas of fire protection. The experience gained from regulating and inspecting existing plants has identified aspects of the plant FPPs that warrant more extensive review. In addition, while a risk-informed approach to new* reactor design review should reflect the experience gained in connection with existing plants, the new reactors include significant design improvements that impact the FPP.

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These design improvements should also be considered when reviewing a license application for a new reactor plant. Finally, in addition to the Browns Fenry fire, there have been other notable plant fires that have provided insight with respect to specific nuclear plant fire risks and how to protect against them (see e.g., IN 2002-27, "Recent Fires at Commercial Nuclear Power Plants in the United States"). The following discussion of the relative risk significance of the various aspects of a plant FPP applies to all new reactors, whether or not they adopt a risk-informed, performance-based FPP.

6.1 Primary Focus of Staff Review Since the new reactor approach to protection of post-fire safe-shutdown capability is to provide installed passive separation of redundant trains, the staff review should focus on the licensee's approach to train separation. The staff should review the detailed definition of train separation; the method of identifying which systems, components and circuits need to be separated; the assumptions upon which adequate separation is determined; the design and testing of the separation barriers; the approach when full separation is not feasible; the method of verifying that the separation barrier is installed and maintained properly; and the method of verifying that the as-built cable routing provides the separation necessitated by the design.

6.2 Aspects of New Reactor FPPs that Reduce Fire Risk The overall maturity of fire protection regulation, nuclear plant operation, and analysis methods and the opportunity to incorporate the benefits in the original plant design will greatly enhance new reactor plant safety. The following aspects of the new reactor FPPs will also enhance post-fire plant safety and should be considered by the staff when reviewing license applications:

a. The enhanced fire protection concept and fully-separated 4-train design reduce the safety significance of fire detection/suppression systems, fire brigade response, and other aspects of the FPP for the areas of the plant where the enhanced level of fire protection is provided.

b. Where the plant's design includes an additional safe-shutdown train to ensure safe-shutdown capability when one train is out for maintenance (i.e., there are at least three 1OO%-capacity redundant trains) and one train fails due to fire, the maintenance downtime for anyone train is likely to be a small percentage of total operating time.

Consequently, there may be a high probability that even with loss of one train from fire, an extra train beyond the minimum required for safe shutdown will be available.

c. Since the fire protection regulations are being incorporated in the original design rather than being backfilled to existing plants, use of the plant change process should be greatly reduced, which should reduce the potential risk increases due to changes.

d. Post-fire, safe-shutdown circuit analysis should be greatly simplified, reducing the potential for errors.

e. Full train separation should significantly reduce security concerns associated with a fire by reducing access needs.

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f. Extensive use of fiber optics should greatly reduce the likelihood of hot shorts and spurious actuations - this development is particularly significant in the control room where full separation of trains is not possible.

g. Use of fiber optics also reduces the fire area combustible loadings and thus the challenge to fire barriers.

h. The enhanced fire protection approach should greatly reduce the importance and scope of fire protection issues that are contentious for existing reactors such as operator manual actions and multiple spurious actuations.

i. The concept of alternative/dedicated shutdown systems, widely used in current reactors, should be virtually eliminated for new reactors (except for a control room or containment fire ).

j. Enhanced fire protection attention to smoke migration and smoke damage should reduce the contribution of these phenomena to overall fire risk.

k. The increased level of passive protection necessary for new reactor designs reduces the potential contribution to overall fire risk from delay in applying water to electrical fires.

I. Use of digital control systems greatly reduces the number and size of electrical cabinets in the control room, reducing (likely to a significant extent) the fire ignition frequency in this critical area.

m. Where used, gel-type batteries may virtually eliminate the hydrogen gas explosion hazard in plant battery rooms.

n. Reactors with passive shutdown systems have reduced combustible loading, reduced ignition sources, and reduced potential for fire-induced equipment failure.

o. Use of polyvinyl chloride and other non-IEEE 1202 rated cable jacketing and insulation should be minimized.

p. The Advanced Boiling Water Reactor (ABWR) and the Economic Simplified Boiling Water Reactor (ESBWR) design plants have no external reactor coolant pumps, eliminating a major fire hazard inside containment. In addition, the containment atmosphere during operation of the ABWR and ESBWR is inerted as with the existing BWR plants.

6.3 Additional Risk Consideration for New Reactor FPPs Turbine buildings remain potentially high-fire-risk areas in new reactor plants. Consideration should be given to the potential risk to adjacent safety related buildings and to ensuring control room or remote shutdown station habitability in the event of a major turbine fire.

7. Fire Protection for Non-Power Operation During shutdown operations, particularly during maintenance or refueling outages, fire conditions can change significantly as a result of work activities. Redundant systems important to safety 9.5.1.1-19 Revision 0 - February 2009

may not be available as described in plant technical specifications and plant procedures. Fire protection during shutdown or refueling conditions should minimize the potential for fire events to impact safety functions (e.g., reactivity control, reactor decay heat removal, SFP cooling) or result in the release of radioactive materials, under the unusual conditions that may be present during these operations.

The guidance for fire prevention in Regulatory Position 2 of RG 1.189 is applicable to all modes of plant operation, including shutdown. License applications for new reactors should also address any special provisions to ensure that, in the event of a fire during a non-power mode of operation, the plant can be maintained in safe shutdown.

8. Alternative Designs and Non-Applicable Acceptance Criteria The new reactor designs that hilVe been reviewed by the NRC have proposed FPP approaches for specific areas of the plant that are not in accordance with the acceptance criteria in RG 1.189. In addition, some of the acceptance criteria in RG 1.189 may not be applicable to some reactor designs. The following are examples of alternative designs that have been accepted by the NRC and plant design features for which the acceptance criteria do not apply.

These are examples and may not include all cases. The reviewer should determine the applicability of the acceptance criteria and the acceptability of any deviations for plant-specific conditions.

8.1 Alternative Designs

a. At least one new reactor design has been certified by the NRC without meeting the guidance in RG 1.189, Regulatory Position 6.1.2.2, to provide detection in control room cabinets and consoles. The acceptance of this approach was based on the low combustible loading in these cabinets and on the continuous occupancy of the control room, which allows rapid detection and response to a fire in the control room.

Acceptance of a similar alternative design for other new reactor designs should be based on the fire hazards analysis.

b. At least one new reactor design has been certified by the NRC without meeting the guidance in RG 1.189, Regulatory Position 6.1.2.1, to provide area automatic fire suppression for control room under-floor areas and ceiling areas. The acceptance of this approach was based on the low combustible loading in these areas and on the continuous occupancy of the control room, which allows rapid detection and response to a fire in the control room. Acceptance of a similar alternative design for other new reactor designs shou Id be based on the fire hazards analysis.

c. At least one new reactor design has been certified by the NRC without meeting the guidance in RG 1.189, Regulatory Position 6.1.2, to provide automatic water suppression in peripheral rooms in the control room complex. The acceptance of this approach was based on the low combustible loading in these areas and on the continuous occupancy of the control room, which allows rapid detection and response to a fire in the control room complex. Acceptance of a similar alternative design for other new reactor designs should be based on the fire hazards analysis.

d. The standpipes and hose stations serving the ESBWR containment are located outside of the containment (the acceptance criteria in RG 1.189, Regulatory Position 6.1.1.2, 9.5.1.1-20 Revision 0 - February 2009

state that the standpipe and hose stations should be located outside of the drywell). The staff found this arrangement to be acceptable because it provided the capability to reach all areas inside the containment with at least one hose stream. The ESBWR containment is inerted during normal power operation and there are multiple access hatches around the perimeter of the containment. This arrangement may also be acceptable for other new reactor designs with inerted containments if the staff finds access and hose station capability is acceptable.

8.2 Non-Applicable Acceptance Criteria

a. In at least one new reactor design (ESBWR), the standby diesel generators are not required for safe shutdown. If these diesel generators are not important to safety, the guidance in RG 1.189 for diesel generator rooms is not applicable (unless the fire hazards analysis identifies an exposure hazard from the diesel generator room to adjacent areas containing equipment or cables important to safety). The staff should consider the diesel generators' importance to safety, as well as the potential impact on adjacent SSCs, when reviewing the fire protection provisions for these areas.

b. Cable spreading rooms typically include circuits that are important to safety and that, therefore, should be protected from fire in accordance with the acceptance criteria. The cable spreading rooms in at least one new reactor design (ESBWR) do not contain any electrical cables or equipment important to safety. The guidance in RG 1.189 for cable spreading rooms is not applicable to these cable spreading rooms (unless the fire hazards analysis identifies an exposure hazard from the cable spreading room to adjacent areas containing equipment or cables important to safety). The staff should consid~r the cable spreading rooms' importance to safety, as well as the potential impact on adjacent SSCs, when reviewing the fire protection provisions for these areas.

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APPENDIXB Supplemental Fire Protection Review Criteria for License Renewal The purpose of this appendix is to provide guidance on the review of the fire protection system in an application for renewal of a nuclear power plant operating license submitted in accordance with the provisions of 10 CFR Part 54, "Requirements for Renewal of Operating Licences for Nuclear Power Plants." RG 1.188, "Standard Format and Content for Applications to Renew Nuclear Power Plant Operating Licenses," provides additional information and guidelines on the renewal process. The RG endorses the methods contained in NEI guideline, NE195-10, "Industry Guideline for Implementing the Requirements of 10 CFR Part 54 - The License Renewal Rule," Revision 0, June 2005. NUREG-1800, Revision 1, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants" and NUREG-1801, Revision 1, "Generic Aging Lessons Learned (GALL) Report" also provide review guidance for license renewal applications.

10 CFR 54.4(a)(3), states, in part, that SSCs relied on in safety analyses or plant evaluations to perform a function that demonstrates compliance with the Commission'S regulations for fire protection (10 CFR Part 50.48) are within the scope of the rule.

NUREG-1800 and NE195-10 provide the methodology for scoping and screening of fire protection SSCs. When evaluating license renewal applications, it is important to note that the scope of SSCs included in 10 CFR Part 50.48 goes beyond the protection of only safety-related equipment. In accordance with GDC 3, "Fire Protection," the scope of equipment required to comply with 10 CFR Part 50.48 is broad and also includes fire protection SSCs needed to minimize the effects of a fire and to prevent the release of radioactive material to the environment - i.e., equipment "important to safety." If applicable, the scoping methods used by an applicant should include review of any commitments made for compliance with Appendix A to BTP APCSB 9.5-1, "Guidelines for fire Protection for Nuclear Plants Docketed Prior to July 1, 1976," or 10 CFR Part 50, Appendix R, "Fire Protection Program For Nuclear Power Facilities Operating Prior to January 1,1979."

10 CFR Part 54.21 states that for those components with intended functions that are identified within the scope of license renewal, those components which are passive (do not perform their functions with moving parts) and long-lived (are not subject to replacement based on qualified life or routine replacement) are subject to an aging management review (AMR). Examples of fire protection components which are passive and long-lived, and that, therefore, would be subject to an AMR, include fire barrier assemblies (e.g. ceilings, damper housing, doors, floors, penetration seals and walls), sprinkler heads, fire suppression system piping and valve bodies, and fire protection tanks and pump casings, and fire hydrant casings. Active components are defined as components that perform an intended function as described in 10 CFR 54.4 with moving parts or with a change in configuration or properties, and they are excluded from the AMR. For example, smoke/heat detectors are considered active components.

Certain passive and long-lived components are considered consumables and, therefore, are not subject to inclusion in the AMR. System filters, fire extinguishers, fire hoses, and air packs (within the scope of license renewal) may be excluded, on a plant-specific basis, from an AMR under 10 CFR Part 54.21 (a)(1)(ii). These components are considered to be within the scope of license renewal and are typically replaced based on specific performance and condition monitoring activities that clearly establish a routine replacement practice based on a qualified life 9.5.1.1-22 Revision 0 - February 2009

of the component. These components may be excluded from an AMR based on specific performance and condition monitoring activities, provided that the applicant (1) identifies and lists in the license renewal application each component type subject to such replacement, and (2) identifies the applicable monitoring and replacement programs that conform to appropriate standards (e.g., NFPA standards).

The applicant should state in the license renewal application that the components are included within scope but excluded from an AMR on the basis of the consumables position. In addition, the application should identify those fire protection system components that the licensee considers to be outside of the scope of eqUipment required for 10 CFR 50.48 compliance as well as the basis for that determination. The license renewal application should include an up-to-date P&ID for the fire protection system that clearly indicates the in-scope portions of the system.

For all components identified within the scope of license renewal and subject to an AMR, programs must be in place to maintain each component's intended function throughout the period of extended operation. NUREG-1801 identifies aging management programs that were determined to be acceptable to manage aging effects of SSCs in the scope of the license renewal as required by 10 CFR 54. For example, the intended function of fire suppression piping or the fire pump casing is to provide a pressure boundary. Programs to manage the aging effects of the pressure boundary can be existing plant programs, modified (or enhanced) programs, or new programs specifically created to address aging concerns. The development of modified or newly created programs is dependent upon (1) the aging effect that needs to be managed, and (2) the ability of the current program to manage the aging effect throughout the period of extended operation.

\

Plants that have installed Halon 1301 extinguishing systems that will be credited during the extended life of the plant should have either a plan for continued access to an adequate supply of replacement Halon or a plan to replace the systern.

Due to the uniqueness of each existing nuclear power plant and to the variations in plant licensing bases, the staff should consider that requirements imposed on one plant are not necessarily applicable to another plant and, sirnilarly, exceptions approved for one plant may not apply to another plant. Each plant should be evaluated based on the site-specific design and licensing basis.

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APPENDIXC Supplemental Fire Protection Review Criteria for Fire Probabilistic Risk Assessments The purpose of this appendix is to provide guidance for the review of the fire protection information to be provided in an application for PRA. An existing plant that has not adopted a risk-informed, performance-based FPP in accordance with 10 CFR 50.48(c) may apply risk-informed methodologies, including fire PRA, to the evaluation of a FPP change. However, the proposed methodologies, including the acceptance criteria, should be reviewed and approved by the NRC prior to the implementation of the plant change.

10 CFR Part 52.47(a)(v) requires that new reactor applications submitted under Part 52 include a design specific probabilistic risk assessment. A detailed fire PRA is not necessarily required for a new reactor FPP. However, if a COL applicant references a DC and if that certified design developed a fire PRA, then the COL applicant, per proposed 10 CFR 52.80(a), is to use that PRA and update it to reflect site and plant-specific information that may not have been available at the design stage. In addition, a licensee that has a risk-informed, performance-based FPP (similar to an NFPA 805 program) or that plans to evaluate plant changes using a risk-informed approach should have a detailed fire PRA.

The term "fire PRA" encompasses all levels and types of PRAs, ranging from a simplified bounding analysis to a detailed analysis in accordance with NUREG/CR-6850 and the draft American Nuclear Society Fire PRA Standard. NUREG/CR-6850 should provide the basis for the review of the proposed methodologies. Refer to SRP Chapter 19, "Probabilistic Risk Assessment," for additional guidance on the review of nuclear power plant PRAs.

A fire PRA should be subjected to a peer review to the extent that adequate industry guidance is

• available. The industry guidance will be reviewed and, if appropriate, accepted by the NRC prior to its application to specific fire PRAs. The results of the plant-specific peer reviews should also be reviewed by the NRC. A peer review should be conducted for all types and levels of fire PRAs. In the event that adequate industry guidance is not available for conducting a fire PRA peer review, the NRC should review the fire PRA for acceptability.

Licensees may use PRA and/or risk insights gained from other methods in support of proposed changes to the plant licensing basis, such as license amendment requests pursuant to 10 CFR 50.90 and 50.92. RG 1.174, "An Approach for Using Probabilistic Risk Assessment In Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," provides guidelines for the use of PRA in support of plant changes that require NRC approval. Plant changes that are not subject to NRC approval are not within the scope of RG 1.174. Where PRA is used by licensees in support of submittals to change the plant licensing basis, the guidelines of SRP Chapter 19 should be followed.

Licensees may apply fire modeling methodologies to a performance-based evaluation of the FPP and to changes to the program. Fire modeling results can provide input to a change evaluation, but the change should also be evaluated for the impact on plant risk, DID, and safety margin. Licensees should document that the fire models and methods used meet NRC requirements. The licensee should also document that the models and methods used in performance-based analyses are used within their limitations and with the rigor required by the nature and scope of the analyses. These analyses may use simple hand calculations or more 9.5.1.1-24 Revision 0 - February 2009

complex computer models, depending on the specific conditions of the scenario being evaluated.

The NRC's Office of Nuclear Regulatory Research and the Electric Power Research Institute have documented the verification and validation (V&V) for parts of five fire models in draft NUREG-1824/EPRI1011999, "Verification and Validation of Selected Fire Models for Nuclear Power Plant Applications." The specific fire models documented are (1) NUREG-1805."Fire Dynamics Tools (FOP)," (2) Fire-Induced Vulnerability Evaluation, Revision 1, (3) the National Institute of Standards and Technology Consolidated Model of Fire Growth and Smoke Transport, (4) the Electricite de France MAGIC code, and (5) the NIST Fire Dynamics Simulator.

Licensees may propose the use of fire models that have not been specifically V&V'd by the NRC; however, licensees are responsible for providing acceptable V&Vofthese fire models.

The V&V documents for licensee-proposed fire models are subject to NRC review and approval.

I 9.5.1.1-25 Revision 0 - February 2009

APPENDIXD Supplemental Fire Protection Review Criteria for Power Uprates The purpose of this appendix is to provide guidance for the review of the fire protection information in an application for a power uprate. Power uprates typically result in an increase in decay heat generation following a plant trip; however, this change usually does not affect the elements of a FPP related to administrative controls, fire suppression and detection systems, fire barriers, the fire protection responsibilities of plant personnel, the procedures and resources necessary for the repair of systems required to achieve and maintain cold shutdown, nor does it usually result in an increase in the potential for a radiological release resulting from a fire. The licensee's submittal should confirm that the power uprate results in no changes to these elements, and this finding should be reflected in the staff's safety evaluation. If the licensee indicates that there is an impact on these elements, the staff should review the impact against the acceptance criteria in the applicable sections of this SRP to ensure that the Commission's fire protection goals are satisfied.

The systems relied upon to achieve and maintain safe shutdown following a fire may be affected by the power uprate due to the increase in decay heat generation following a plant trip. For fire events where the licensee is relying on one full train of the redundant systems normally used for safe shutdown, the licensee's analysis of the impact of the power uprate on the important plant process parameters performed for other plant transients, such as a loss of off-site power or a loss of main feedwater, will typically bound the impact for a fire event such that a specific analysiS for fire events is not necessary. However, where a licensee relies on less than full capability systems for fire events, such as partial automatic depressurization or a reduced capability makeup pump, the licensee should provide a specific analysis for fire events that demonstrates that the fuel design limits are not exceeded, that fuel integrity is maintained and that there are no adverse consequences on the reactor pressure vessel integrity or the attached piping. Licensees that rely on alternative/dedicated or backup shutdown capability for post-fire safe shutdown should analyze the impact of the power uprate on the alternative/dedicated or backup shutdown capability. The staff should verify that the alternative/dedicated or backup systems relied upon for post-fire safe shutdown are capable of achieving and maintaining safe shutdown considering the impact of the power uprate.

The plant's post-fire safe-shutdown procedures may also be impacted by the power uprate. For example, the allowable time to perform necessary operator actions may decrease as a result of the power uprate and the necessary flow rates for systems required to achieve and maintain safe shutdown may need to be increased. The licensee should identify the impact of the power uprate on the plant's post-fire safe-shutdown procedures.

RIS-001, Revision 0, "Review Standard for Extended Power Uprates," provides additional guidance for the review of applications for power uprate.

9.5.1.1-26 Revision 0 - February 2009

SRP Section 9.5.1.1 Description of Changes The section is currently being issued as 9.5.1.1, Revision 0, February 2009, to reflect re-numbering as result of issuance of the new SRP Section 9.5.1.2, "Risk-Informed and Performance-Based Fire Protection Program," (ADAMS accession no. ML090050038). This revision renumbers the current SRP Section 9.5.1, Revision 5 to 9.5.1.1, Revision 0 to be consistent with the topic number in the chapter table.

9.5.1.1-27 Revision 0 - February 2009

NUREG-0800 u.s. NUCLEAR REGULATORY COMMISSION STANDARD REVIEW PLAN 9.5.1.2 RISK-INFORMED, PERFORMANCE-BASED FIRE PROTECTION PROGRAM REVIEW RESPONSIBILITES Primary - Organization responsible for the review of fire protection.

Secondary - Organization responsible for the review of risk-informed (RI) licensing actions I. AREAS OF REVIEW This chapter of the Standard Review Plan (SRP) provides guidance for the U.S. Nuclear Regulatory Commission (NRC) staff who reviews RI, Performance-Based (PB)Fire Protection Program (FPP) license amendment requests (LARs) submitted pursuant to 10 CFR 50.48(c) and the guidance in Regulatory Guide (RG) 1.205 "Risk-Informed, Performance-Based Fire Protection for Existing Light-Water Nuclear Power Plants." This guidance is applicable to 1 existing operating reactor licensees under Title 10 of the Code of Federal Regulations, Part 50 (10 CFR Part 50) and covers the review of LARs fortransition and post-transition to an RI/PB FPP based on National Fire Protection Association (NFPA) Standard 805. Also, the staff previously issued an update to SRP Section 9.5.1 in March, 2007; for the benefit of Combined License (COL) applicants under 10 CFR part 52. SRP Section 9.5.1 focused on deterministic Rev. 0 - January 2009 USNRC STANDARD REVIEW PLAN This Standard Review Plan (SRP), NUREG-0800, has been prepared to establish criteria that the U.S. Nuclear Regulatory Commission staff responsible for the review of applications to construct and operate nuclear power plants intends to use in evaluating whether an applicanUlicensee meets the NRC's regulations. The Standard Review Plan is not a substitute for the NRC's regulations, and compliance with it is not required. However. an applicant is required to identify differences between-the design features, analytical techniques, and procedural measures proposed for its facility and the SRP acceptance criteria and evaluate how the proposed alternatives to the SRP acceptance criteria provide an acceptable method of complying with the NRC regulations.

The standard review plan sections are numbered in accordance with corresponding sections in Regulatory Guide 1.70, "Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants (LWR Edition).~ Not all sections of Regulatory Guide 1.70 have a corresponding review plan section. The SRP sections applicable to a combined license application for a new light-water reactor (LWR) are based on Regulatory Guide 1.206, "Combined License Applications for Nuclear Power Plants (LWR Edition)."

These documents are made available to the public as part of the NRC's policy to infonn the nuclear industry and the general public of regulatory procedures and policies. Individual sections of NUREG-0800 will be revised periodically, as appropriate, to accommodate comments and to reflect new information and experience. Comments may be submitted electronically by email to NRR_ SRP@nrc.gov.

Requests for single copies of SRP sections (which may be reproduced) should be made to the U.S. Nuclear Regulatory Commission, Washington, DC 20555, Attention: Reproduction and Distribution Services Section, or by fax to (301) 415-2289; or by email to DISTRIBUTION@nrc.gov. Electronic copies of this section are available through the NRC's public Web site at http://www.nrc.gov/reading-rm/doc-coliections/nuregs/staff/sr08 00/, or in the NRC's Agencywide Documents Access and Management System (ADAMS), at http://www.nrc.gov/reading-rm/adams.html. under Accession # ML090050052.

Enclosure 13

FPPs and advised that the primary review guidance document for NFPA 805 plants would be developed in the future. SRP Section 9.5.1.2 provides this guidance. Note that only the review of RI/PB FPP LARs is covered by this SRP section. For example, exemptions from Appendix R to 10 CFR Part 50 requirements or deviations from NUREG-0800 Chapter 9.5.1 license commitments are not covered in this SRP section.

In developing this SRP section, the staff considered requirements of 10 CFR 50.48(c) and NFPA 805 to the extent it is incorporated into 10 CFR 50.48(c). The staff also considered the guidance provided by RG 1.205 which endorses with exceptions Nuclear Energy Institute (NEI)

NEI 04-02, "Guidance for Implementing a Risk-Informed Performance-Based Fire Protection Program Under 10 CFR 50.48(c)" revision endorsed in RG 1.205. Atthe time of drafting this SRP section, some of the documents referenced herein are subject to revision, like RG 1.205 and NEI 04-02. For example, the referenced documents may be reorganized, which would affect the specific section references in this SRP section. A reviewer should use the most current revision of RG 1.205 for accurate references. In addition, the staff incorporated staff positions developed using experience from NFPA 805 implementation. The staff has documented these additional staff positions via the NFPA 805 Frequently Asked Questions (FAQ) Process. [RIS 2007-19]

Review Areas A FPP for a nuclear power plant (NPP) licensed to operate generally consists of the following elements: [RG 1.189]

• Delineation of organization, staffing, and responsibilities

• Performance of a fire hazards analysis sufficient to ensure safe shutdown functions and minimize radioactive material releases in the event of a fire

• Limitation of damage to structures, systems and components (SSCs) important to safety so that the capability to safely shut down the reactor is ensured

• Evaluation of fire test reports and fire data to ensure they are appropriate and adeq uate for ensuring compliance with regulatory requirements

• Evaluation of compensatory measures for interim use for adequacy and appropriate length of use

• Training and qualification of fire protection personnel appropriate for their level of responsibility

• Quality assurance

• Control of FPP changes The staff reviews the overall RI/PB FPP described in the LAR with respect to the acceptance criteria in this SRP and the Acceptance Review Matrix attached to this SRP section (Attachment 1). Specifically, the staff reviews the following, as applicable:

1. Orders and license conditions that the licensee has identified as needing to be revised or superseded 9.5.1.2-2 Rev. 0 - January 2009

2. Revised technical specifications (TSs), including Administrative Controls and Limiting Conditions for Operation and their bases

3. Proposed Updated Final Safety Analysis Report (UFSAR) changes related to the FPP if provided

4. Plant modifications and other changes that the licensee has identified as necessary to implement the RI/PB FPP, including the schedule for implementation and justification of the schedule

5. Process for self-approving RI/PB FPP changes post-transition, including the types of RI/PB changes that the licensee intends to self approve, the capability of the Fire Probabilistic Risk Assessment (PRA) to model those changes, and the method used to establish a cause-effect relationship to estimate the change in risk associated with the performance based alternative

6. Statements on no Significant hazards consideration and environmental considerations

7. Licensee's request per 10 CFR 50.48(c)(2)(vii) to subject the fundamental FPP and design elements of Chapter 3 of NFPA 805 to the PB methods permitted elsewhere in the standard

8. Licensee's request per 10 CFR 50.48(c)(4) to use RI/PB alternatives to compliance with NFPA 805 including details of the proposed alternatives

9. Licensee's description of oP'llrational guidance provided to plant personnel detailing the success path(s) for each fire area and the performance of recovery actions (RAs)

10. Engineering analyses required by NFPA 805 Section 2.4, "Fire Modeling, Nuclear Safety Capability Assessment, and Fire Risk Evaluations"

11. Any FAQs cited by the licensee. For FAQs that have not been closed by the NRC, the licensee's detailed description and justification for their use in the submittal

12. Plant structures that comprise the power block as defined in NFPA 805

13. Verification that feed-and-bleed is not relied on as the only path to post-fire safe shutdown in pressurized-water reactors (PWRs) for safe shutdown

14. Pre- and post-transition regulatory basis for each fire area, including methods used to accomplish NFPA 805 performance criteria, disposition of deviations/exemptions, existing engineering equivalency evaluations (EEEEs), and any associated risk assessment results

15. Fire protection during non-power operational modes to ensure that nuclear safety performance criteria are met

16. Results of the Nuclear Safety Capability Assessment for Radioactive Release to ensure that the radioactive release goals and performance criteria have been met 9.5.1.2-3 Rev. 0 - January 2009

17. Basis for the technical adequacy of the fire PRA model, or model parts, being used to perform change evaluations and the process for assuring the PRA model is maintained and updated to reflect the as-built, as-operated and maintained plant, and operating experience of the plant as needed to support any proposed self approval process

18. Methods used to estimate the change in risk for each type of performance based approach, a sample of the calculations as appropriate, and verify that the change in risk is within the acceptance guidelines, including resultant risk increase/decrease, and how defense-in-depth (DID) and safety margins are maintained for each change

19. Monitoring program, including bases for failure probability assumptions used in the fire PRA, methods used to monitor availability, reliability, and performance of FPP systems, and processes for identifying and implementing corrective actions

20. FPP documentation, including the FPP design basis document and supporting documents, and the Licensee's configuration control process for the FPP and associated analyses

21. Process for assuring quality for each FPP analysis, calculation, and evaluation

22. Fire-induced multiple spurious operations (MSOs), including the process used to identify and screen MSOs and how each is evaluated in the fire PRA

23. Operator manual actions (OMAs) transitioning to RAs, including documentation for those that have been previously approved by the NRC and that those RAs that are credited with achieving the nuclear safety performance criteria are feasible and reliable

24. Change in risk associated with relying on RAs instead of NFPA 805 requirements

25. Process for resolving issues with electrical raceway fire barrier systems (e.g., Hemyc and/or MT)

Review Interfaces Other SRP Sections interface with this Section as follows:

SRP Section 19.1, "Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities."

SRP Section 19.2, "Review of Risk Information Used to Support Permanent Plant-Specific Changes to the Licensing Basis: General Guidance."

SRP Section 9.5.1, "Fire Protection Program."

9.5.1.2-4 Rev. 0 - January 2009

II. ACCEPTANCE CRITERIA Section II lists the governing regulations applicable to the areas of review in this SRP Section and the primary guidance documents that provide acceptable methods for meeting the regulatory requirements.

Requirements

• The licensee's FPP will generally be considered acceptable if it meets the applicable criteria established in the following:

1. General Design Criterion (GDC) 3, "Fire protection," in Appendix A, "General Design Criteria for Nuclear Power Plants," to 10 CFR Part 50, which establishes the general criteria for fire and explosion protection of SSCs important to safety

2. 10 CFR 50.48(a), which requires that each operating NPP have a fire protection plan that meets the requirements of GDC 3

3. 10 CFR 50.48(c), which incorporates NFPA 805 (2001 Edition) by reference, with certain exceptions. This regulation establishes the requirements for using NFPA 805 as an alternative to the requirements associated with 10 CFR 50.48(b) and Appendix R to 10 CFR Part 50 or the specific plant license condition.

4. NFPA 805 (2001 Edition), which documents the consensus standard for RI/PB fire protection of existing NPPs, to the extent incorporated by refEtrence by 10 CFR 50.48(c)

5. 10 CFR Part 20, "Standards for Protection Against Radiation," which establishes the radiation protection limits used as NFPA 805 performance criteria, as specified in Section 1.5.2 of NFPA 805 SRP Acceptance Criteria Specific SRP criteria acceptable to meet the relevant requirements of the NRC's Regulations identified above are as follows for the review described in this SRP section. The SRP is not a substitute for the NRC's regulations, and compliance with it is not required. However, an applicant is required to identify differences between the design features, analytical techniques, and procedural measures proposed for its facility and the SRP acceptance criteria and evaluate how the proposed alternatives to the SRP acceptance criteria provide acceptable methods of compliance with the NRC regulations.

The following documents provide acceptable methods, guidance, and other criteria applicable to meeting the Commission's FPP requirements:

1. NUREG-1600, "General Statement of Policy and Procedure for NRC Enforcement Actions, Interim Enforcement Policy, May 1, 2000," which provides the Commission's policy on enforcement discretion for non-compliant conditions, either eXisting or identified during transition to an RI/PB FPP in accordance with 10 CFR 50.48(c) 9.5.1.2-5 Rev. 0 - January 2009

2. RG 1.205, "Risk-Informed, Performance-Based Fire Protection for Existing Light-Water Nuclear Power Plants," Which provides NRC guidance on an acceptable approach to meeting 10 CFR 50.48(c), including endorsement (with exceptions) of NEI 04-02, "Guidance for Implementing a Risk-Informed Performance-Based Fire Protection Program Under 10 CFR 50.48(c)," and portions of NEI 00-01, "Guidance for Post-Fire Safe Shutdown Circuit Analysis"

3. RG 1.174, Revision 1, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," which provides NRC guidance on an acceptable method to assess the nature and impact on licensing basis changes using risk information within the context of applicability under 10 CFR 50.48(c) and RG 1.205

4. RG 1.189, Revision 2, "Fire Protection for Nuclear Power Plants," which provides general guidance on acceptable FPPs

5. Section 19.1 of the SRP, "Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," which provides review guidance on determining the technical adequacy of PRA models for RI initiatives

6. Section 19.2 of the SRP, "Review of Risk Information Used to Support Permanent Plant-Specific Changes to the Licensing Basis: General Guidance," which provides guidance on reviewing risk information used to support plant-specific changes to the licensing basis

7. RG 1.200, Revision 2, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk Informed Activities," issue date to be determined (TBD), which provides guidance with respect to acceptable methods and PRA quality

8. NUREG/CR-6850, "EPRI/NRC-RES Fire PRA Methodology for Nuclear Power Facilities," Volumes 1 and 2, issued September 2005, which provides a method for developing a fire PRA in support of adopting an RI/PB FPP, within the context of the additional clarification provide by the staff via the NFPA 805 FAQ process.

9. NUREG-1852, "Demonstrating the Feasibility and Reliability of Operator Manual Actions in Response to Fire," which provides qualitative methods to demonstrate that OMAs are feasible and reliable

10. NUREG-1824, "Verification and Validation of Selected Fire Models for Nuclear Power Plant Applications," Volumes 1-7, issued May 2007, which provides guidance on (V&V) of fire models III. REVIEW PROCEDURE Licensees of existing plants that wish to adopt an RI/PB FPP that complies with NFPA 805 must submit a LAR in accordance with 10 CFR 50.48(c)(3)(i). Licensees that wish to adopt 10 CFR 50.48(c) but wish to use PB methods permitted elsewhere in NFPA 805 for the Chapter 3, 9.5.1.2-6 Rev. 0 - January 2009

"Fundamental Fire Protection Program and Design Elements," of NFPA 805 may do so by submitting an LAR in accordance with 10 CFR 50.48( c)(2)(vii). Licensees that wish to use RI/PB alternatives to compliance with NFPA 805 must submit an LAR in accordance with 10 CFR 50.48(c)(4). In addition to the LARs required by the rule, licensees may submit additional elements of their program for which they wish to receive specific NRC review and approval as set forth in RG 1.205, "Risk-Informed, Performance-Based Fire Protection for EXisting Light-Water Nuclear Power Plants," Regulatory Position 2.2.

• The review of an LAR starts with an acceptance review by the NRC staff in accordance with Office of Nuclear Reactor Regulation (NRR) Office Instruction LlC-109, "Acceptance Review Procedures." Attachment 1 of this SRP includes an acceptance review matrix as an aid in performing the acceptance review of the LAR. Once an LAR is accepted as sufficient for the staff to begin its review, the staff review proceeds in accordance with LlC-101, "License Amendments." If deemed appropriate for a given review, a regulatory audit of the licensee may be conducted in accordance with LlC-111, "Regulatory Audits," for the staff to gain a better understanding of the licensee's calculations, proposed plant modifications; and other aspects of the LAR.

The NRC staff reviewing LARs to implement an RI/PB FPP should be aware of the NFPA 805 FAQ Process. The NRC established the FAQ process as described in RIS 2007-19, "Process for Communicating Clarifications of Staff Positions Provided in Regulatory Guide 1.205 Concerning Issues Identified during the Pilot Application of National Fire Protection Association Standard 805," to clarify issues encountered during the pilot transition. The FAQ process provides a means for the staff to establish and communicate interim positions on technical and regulatory issues that emerge as experience is gained in the review of these LARs. Approved I interim positions documented through the FAQ process should be used where applicable in reviewing those portions of an LAR to which they apply. These positions will be formalized in future revisions of RG 1.205 and reflected in this SRP.

111.1 PROGRAMMATIC REVIEW OF LICENSE AMENDMENT REQUEST The required content of an LAR for transition to an RIIPB FPP is defin"ed in 10 CFR 50.48(c)(3)(i), 10 CFR 50.90 and, as applicable, 10 CFR 50.48(c)(2)(vii) and 10 CFR 50.48(c)(4). Regulatory Position 2.2 of RG 1.205 and Section 4.6.1 of NEI 04-02, provide additional guidance on the content of the LAR. 10 CFR 50.48(c)(3)(ii) requires the licensee to perform the required analyses and revise the fire protection plan prior to changing either the plant or the FPP.

Section 2.2 of NFPA 805 provides the general approach for establishing the fire protection requirements for a NPP. Section 3.3 of NEI 04-02 provides additional detail on implementing this approach. The NRC staff will review the LAR to verify that each step in the process has been satisfactorily completed.

111.1.1 Orders, License Condition, and Technical Specifications The NRC staff will confirm that the licensee has identified any orders and license conditions that must be revised or superseded, and provided any necessary revisions to the plant's technical specifications and the bases thereof to implement a FPP that complies with NFPA 805. The 9.5.1.2-7 Rev. 0 - January 2009

reviewer should ensure that the LAR includes a discussion of the changes to the UFSAR necessitated by the license amendment. [NEI 04-02 paragraph 4.6.1]

The staff will verify that the LAR provides updated TSs. The staff will verify that the package includes the following (as identified by the licensee):

• Changed, added or revoked Administrative Controls

• Revised or superseded Limiting Conditions for Operation, ensuring that they are consistent with 10 CFR 50.48(c) and 10 CFR 50.36

• Revised associated Bases as required by 10 CFR 50.48(c)(3)(i)

The reviewer must keep in mind that there will likely be other requirements that must be met with regard to remote shutdown capability to meet GDC 19 of 10CFR 50, Appendix A, "Control Room." The reviewer will confirm that the licensee does not inadvertently delete the TSs associated with remote shutdown requirements required by other regulations related to the ability to safely shut down from outside the control room.

111.1.2 Modifications The staff will ensure that the license condition lists any plant modifications that the licensee has identified as necessary to implement the RIIPB FPP and includes a description of the modification, a schedule for implementation of the modification, and a commitment to maintain in effect compensatory measures until the modification is completed.

111.1.3 Self-Approval of Certain FPP Changes After a licensee implements NFPA 805, it may implement changes to its FPP in accordance with the license condition approved by the NRC staff. A plant change evaluation as described in paragraph 111.5.3 of this SRP is required for any change to a previously approved FPP element.

A change may be any of the following: [RG 1.205 regUlatory position 3.2.1]

(a) A physical plant modification that affects the FPP; (b) A programmatic change (e.g., change to a procedure, assumption or analysis) that affects the FPP; or, (c) An in situ condition (physical or programmatic) that is an FPP regulatory noncompliance or a fire protection licensing-basis noncompliance, which the licensee does not intend to correct via a plant or programmatic modification.

The NRC staff will review the licensee's process for self-approving changes and determine whether the licensee has adequate processes in place to ensure that acceptable PRA technical adequacy is maintained, and that DID and safety margins are appropriately addressed after transition.

9.5.1.2-8 Rev. 0 - January 2009

The staff will ensure that the license condition identifies whether the licensee is permitted to make certain changes to the FPP without prior NRC review and approval, and, if so, the risk acceptance criteria and any restrictions in terms of the types of changes that may be so implemented. Note that Section 3.2.4 of RG 1.205 lists FPP changes that always require prior NRC approval.

• RG 1.205 Regulatory Position 3.1 contains a sample license condition that allows for self-approval of FPP changes. The staff will verify that the license condition contains sufficient detail to ensure self-approval meets these regulatory positions.

Note: Licensees may reference methods in NRC approved topical reports (TR). This option affords efficiencies both for licensees and NRC. A licensee must still request approval to adopt the alternative approved in the TR by applying for a license amendment which demonstrates the licensee has met the criteria in the TR for such adoption. [NEI 04-02 paragraph 2.4.2]

111.1.4 Significant Hazards Consideration The staff will verify that the LAR includes a statement concerning the "no significant hazards consideration," in accordance with 10 CFR 50.91 and 10 CFR 50.92. Appendix H to NEI 04-02 provides one example of an acceptable statement.

111.1.5 Environmental Consideration (Categorical Exclusion Finding)

The staff will verify that the LAR includes a statement on environmental considerations in 1 accordance with 10 CFR 51.22(b) and (c). Appendix H to NEI 04-02 provides one example of an acceptable statement.

111.1.6 Transition Implementation Schedule The staff will verify that the LAR includes an "updated transition schedule" per Section 4.6.1 of NEI 04-02. The submittal will provide a transition schedule, justification for the schedule, and a list of modifications with a commitment to maintain in effect associated compensatory measures. The staff will ensure that the proposed schedule is reasonable.

111.1.7 Performance-Based Methods for NFPA 805 Chapter 3 Elements Notwithstanding the prohibition in Section 3.1 of NFPA-805, a licensee can request NRC approval under 10 CFR 50.48(c)(2)(vii), via a license amendment, to apply PB methods permitted elsewhere in the standard (Le. NFPA 805 4.2.4) to the fundamental FPP and design elements of Chapter 3 of NFPA 805. Where a licensee proposes to use PB methods to demonstrate compliance with the fundamental FPP and design elements in Chapter 3 of NFPA 805, the NRC staff will review the LAR in accordance with 10 CFR 50.48(c)(2)(vii) and RG 1.205, Regulatory Position 3.2.3, to verify the adequacy of the methods and the licensee's evaluation and conclusions.

111.1.8 Risk-Informed, Performance-Based Alternatives to Compliance with NFPA 805 NFPA 805 provides one framework describing how PB, RI methods may be used to self-approve plant changes that affect the FPP program. Other frameworks may be acceptable.

9.5.1.2-9 Rev. 0 - January 2009

Under 10 CFR 50.48(c)(4), a licensee may request NRC approval to use RI or PB alternatives (i.e., different from those prescribed by NFPA 805) to demonstrate compliance with 10 CFR 50.48(c) using the LAR process. In those instances, the NRC staff will review the LAR in accordance with 10 CFR 50.48(c)(4) to verify that all of the following are true for the proposed alternative and its application:

(a) It satisfies the perforrnance goals, objectives, and criteria specified in NFPA 805 related to nuclear safety and radiological release; (b) It maintains safety margins; and, (c) It maintains fire protection DID (fire prevention, fire detection, fire suppression, mitigation, and post-fire safe-shutdown capability).

Regulatory Position 3.2.3 of RG 1.205 provides additional guidance regarding the information to be supplied by the licensee when requesting NRC staff approval for alternative RIIPB methods; the licensee should provide:

(a) A detailed description of the alternative RIIPB method (b) A description of how the method will be applied, the aspects of the FPP to which it will be applied, and the circumstances under which it will be applied (c) The acceptance criteria, including risk increase acceptance criteria, that the licensee will apply when determining whether the results of an evaluation that uses this methodology meet the required NFPA 805 performance goals, performance objectives, and performance criteria (d) For risk assessments using PRA methods, a justification of the technical adequacy of the PRA model per RG 1.200 for evaluation of the changes to which it will be applied (e) For risk assessments using PRA methods, a description of the peer review and how the review findings have been addressed.

The NRC staff's review of LARs submitted in accordance with 10 CFR 50.48(c)(4) will focus on the technical aspects of the approach or method proposed as an alternative to compliance with NFPA 805. The approach or method shall meet an equivalent level of protection to that established by NFPA 805. The staff will review a sample of the calculations to verify that the licensee's evaluation and conclusions with regard to meeting the safety margin and DID criteria are acceptable. Proposed alternatives are subjected to the same evaluation criteria (e.g., V&V) as the endorsed methods. The reviewer will also evaluate the LAR to verify that the licensee adequately performed and documented these evaluations.

111.2 FUNDAMENTAL FIRE PROTECTION PROGRAM ELEMENTS AND MINIMUM DESIGN REQUIREMENTS Chapter 3 of NFPA 805 establishes the fundamental FPP and design elements. The NRC staff will review the LAR to verify that the licensee complies with the fundamental FPP and design elements required by Chapter 3 of NFPA 805.

9.5.1.2-10 Rev. 0 - January 2009

The staff will review the LAR to evaluate the applicant's overall approach to determining how its FPP complies with the requirements of NFPA 805 Chapter 3 requirements. The approach in NEI 04-02 as endorsed in RG 1.205 is one approach acceptable to the NRC.

Chapter 3 of NFPA 805 notes that alternatives to the fundamental FPP attributes of Chapter 3, which were previously appr()\/ed by the NRC, take precedence over the requirernents in Chapter

3. If the licensee references previous NRC approvals of exemption or deviation requests, the NRC staff will review the documentation demonstrating prior NRC approval. The documentation should contain justification that the exemption or deviation is still valid. [RG 1.205 regulatory position 2.4]

111.2.1 Water Supply and Distribution 10 CFR 50.48(c)(2)(vi) modifies NFPA 805 paragraph 3.6.4 by not endorsing the italicized exception; i.e., a "provisional" manual fire fighting standpipe/hose station system may not be used in place of seismically qualified standpipes and hose stations unless previously approved in the licensing basis. Licensees who wish to use the italicized exception in Section 3.6.4 of NFPA 805 must submit a request for a license amendment in accordance with 10 CFR 50.48(c)(2)(vii). However, because the NRC considers seismically qualified standpipes

• and hose stations to be of such importance, the NRC reviewer must ensure that the three criteria in 10 CFR 50.48(c)(2)(vii) are satisfied.

Note that Appendix A to Branch Technical Position (BTP) AUXiliary and Power Conversion Systems Branch (APCSB) 9.q-1, "Guidelines for Fire Protection for Nuclear Power Plants,"

dated February 24,1977, makes separate provisions for operating plants and plants with construction permits issued before July 1, 1976, and does not require seismically qualified standpipes and hose stations for those plants. Therefore, the requirement in Section 3.6.4 of NPFA 805 is not applicable to licensees with non-seismic standpipes and hose stations previously approved in accordance with Appendix A to BTP APCSB 9.5-1.

111.2.2 Definition of Power Block The staff will review the LAR to determine which plant structures are identified as comprising the "power block." The reviewer should verify that the licensee's list of power block structures conforms to the definition of "power block" in the glossary of NFPA 805, which defines power block as "structures that have equipment required for nuclear plant operations."

111.2.3 Electrical Raceway Fire Barrier Systems (e.g. Hemyc and MT)

On April 10, 2006, the NRC issued Generic Letter 2006-03, "Potentially Non-Conforming Hemyc and MT Fire Barrier Configurations," requiring licensees to provide information regarding the use of electrical raceway fire barriers, particularly Hemyc and MT, at their plants. If the applicant has not resolved the electrical raceway fire barrier issue prior to submittal of their RI/PB FPP LAR, the applicant must address the issue in the LAR. The staff will verify that the applicant has adequately addressed this issue, including having provided a justification for the use of any compensatory measures and proposed plant modifications.

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111.3 NUCLEAR SAFETY PERFORMANCE CRITERIA Chapter 2 of NFPA 805 provides the methodology to be used in implementing a PB FPP. NEI 04-02 Section 4.3.2 sets out a systematic process for evaluating the existing post-fire safe shutdown analysis against the methodology requirements provided in Chapter 2 of NFPA 805.

RG 1.205 endorses the deterministic post-fire safe shutdown analysis methodology provided in Chapter 3 of NEI 00-01.

111.3.1 Transition and Implementation 10 CFR 50.48(c)(3)(ii) states that Chapter 2 analyses shall be completed and the fire protection program plan modified before changing the FPP and the plan as permitted by NFPA-805.

The staff will ensure that the licensee has adequately performed the engineering analyses required by NFPA 805, Section 2.4 including fire modeling, nuclear safety capability assessment and fire risk evaluations.

The staff will ensure that the licensee completed a systematic approach to transition the FPP to the new requirements in NFPA 805. As endorsed in RG 1.205, Section B-2 of Appendix B to NEI 04-02 describes one acceptable approach to documenting the comparison of an existing FPP with the requirements of NFPA 805 and industry guidance document NEI 00-01.

In evaluating nuclear safety performance criteria transition, staff will reference Section 1.5 of NFPA 805, which establishes the nuclear safety performance criteria, and Chapter 4 of NFPA 805, which provides the methodology to determine the fire protection systems and features required to achieve the performance criteria outlined in Section 1.5.

The staff will review the LAR to determine whether the nuclear safety performance criteria have been met consistent with the requirements in NFPA 805. The staff will ensure licensee compliance with the following requirements:

111.3.1.1 Feed-and-Bleed 10 CFR 50.48(c)(2)(iii) specifically notes that use offeed-and-bleed as the sole fire-protected safe-shutdown path for maintaining reactor coolant inventory, pressure control, and decay heat removal capability is not permitted for pressurized water reactors. The staff will determine if the LAR includes a statement to this effect as well as a description of any dependence on feed-and-bleed in the FPP.

111.3.1.2 Existing Cables NFPA 805 paragraph 3.3.5.3 states that electrical cables shall meet a flame propagation test that is acceptable to the authority having jurisdiction. 10 CFR 50.48(c)(2)(v), which does not endorse the italicized exception in NFPA 805 paragraph 3.3.5.3, allows a flame retardant coating on the cables or an automatic fixed suppression system to provide an equivalent level of protection.

9.5.1.2-12 Rev. 0 - January 2009

The NRC staff will review the LAR to verify that the requirements for existing cables are met. If the NRC staff approves use of these alternatives, this approval should be explicitly documented in the staff's safety evaluation report.

Note that the flame spread testing requirements in IEEE 383, "IEEE Standard for Type Test of Class 1E Electric Cables, Field Splices, and Connections for Nuclear Power Generating Stations," are now provided in IEEE 1202, "IEEE Standard for Flame-Propagation Testing of Wire and Cable," and have been removed frorn the current version of IEEE 383. Most existing plants reference earlier versions of IEEE 383 and have approved FPPs based on this standard.

Plants that reference IEEE 383 are not required to meet IEEE 1202 when transitioning to a RI/PB FPP.

111.3.1.3 Fire-/nduced Mu/tiple Spurious Operations Section 2.4.2.2 of NFPA 805 requires the applicant to evaluate fire-induced failure modes resulting from spurious operations and signals, including multiples, as a part of their safe shutdown circuit analysis. The description of the MSO analysis should contain sufficient information concerning methods, tools, and acceptance criteria used to enable the staff to determine the acceptability of the licensee's rnethodology. The analysis should generally be performed and arranged by fire area, although in some cases an alternative spatial approach rnay prove to be more practical. If an expert panel process was used, it should be documented with results clearly presented. The NRC staff will verify that the applicant has evaluated MSOs in conformance with Regulatory Position 3.3 of RG 1.205.

111.3.2 Specific Compliance with NFPA 805 by Fire Area \

The staff will review the LAR to ensure that each fire area has been evaluated and determined to comply with the requirements of NFPA 805. The staff will verify that each fire area either meets NFPA 805 paragraph 4.2.3 deterministic requirements; meets the NFPA 805 paragraph 1.5 performance criteria as demonstrated using PB rnethods as allowed under NFPA 805 paragraph 4.2.4; or meets the NFPA 805 paragraph 1.5 performance criteria as dernonstrated using RI or PB alternatives to compliance with NFPA 805 pursuant to 10 CFR 50.48(c)(4).

Refer to paragraph 111.1.8 of this SRP Section for further information on alternatives.

111.3.2.1 Deterministic Compliance with NFPA 805 Section 4.2.3 For each fire area where the licensee has selected the deterministic approach to demonstrate compliance, the staff will verify that the deterministic requirements of NFPA 805 paragraph 4.2.3 are met. Licensees may demonstrate compliance through:

a) Compliance with the deterministic requirements of NFPA 805 through the use of previously approved exemptions/deviations from their current licensing basiS; or, b) The use of an engineering equivalency evaluation of an existing configuration to demonstrate an equivalent level of fire protection compared to the deterministic requirements. [NFPA 805 paragraph 2.2.7]

Previously approved exemptions/deviations (norrnally from Appendix R requirements) describe plant configurations that the staff has determined to be acceptable, notwithstanding that 9.5.1.2-13 Rev. 0 - January 2009

Appendix R or NFPA-805 may require some other configuration. Such plant configurations may be deemed to satisfy the deterministic requirements of NFPA-805 provided the basis for acceptability of these previously approved exemption/deviations continues to be valid.

EEEEs that support deviations from the requirements and methods of NFPA 805 must be submitted for NRC approval as part of the transition to NFPA 805. [RG 1.205 regulatory position 2.3] These EEEEs include those commonly referred to as a "Generic Letter 86-10 evaluations, which were developed by the licensee without prior NRC review or approval. The staff will verify that EEEEs supporting deviations from the requirements and methods of NFPA 805 clearly demonstrate an equivalent level of fire protection compared to the deterministic requirements. Guidance for acceptable EEEEs is provided in NUREG-0800, Section 9.5.1, "Fire Protection," and in Regulatory Guide 1.189, "Fire Protection for Operating Nuclear Power Plants."

OMAs that are currently allowed or were previously reviewed and approved by the NRC's Office of NRR that meet the NFPA 805 definition of an RA automatically shall imply use of the PB approach as outlined in NFPA 805 paragraph 4.2.4.

111.3.2.2 Performance-Based Compliance with NFPA 805 Section 4.2.4 For each fire area where the licensee has selected the PB approach, the staff will verify that the requirements of NFPA 805 paragraph 4.2.4 are met. A PB approach is necessary if the deterministic requirements of NFPA 805 are not satisfied.

The NRC staff will verify that the change in risk is appropriately defined, the magnitude is acceptable (Section 111.5.5 of this.SRP), and DID and sufficient safety margins are maintained (Section 111.5.2 of this SRP).

If the fire modeling PB approach is employed, the NRC staff will verify that the requirements of NFPA 805 paragraph 4.2.4.1 are met. The staff will verify that the licensee has made a statement in the LAR confirming that it has provided the operational guidance required by NFPA 805 paragraph 4.2.4.1.6, and that all RAs are feasible. NUREG-1852 is one acceptable PB approach that can be used in judging the feasibility and reliability of RAs.

If the fire risk evaluation PB approach is employed, the NRC staff will review the integrated assessment of the acceptability of risk, DID, and safety margins per Section 111.5.5 of this SRP.

The staff will review OMAs that the licensee desires to transition to RAs. If the licensee has chosen to use the PB approach because the licensee credits RAs, the NRC staff will review the licensee's evaluation of the additional risk per Section 111.5.4 of this SRP.

111.3.2.3 Risk-Informed or Performance-Based Alternatives to Compliance with NFPA 805 For each fire area where the licensee has selected RI or PB alternatives to compliance with NFPA 805, the staff will verify that the appropriate requirements are met. Refer to paragraph 111.1.8 of this SRP section for information relating to these alternatives.

9.5.1.2-14 Rev. 0 - January 2009

111.3.3 Non-Power Operational Modes The staff will review the licensee's treatment of fires during non-power operations (NPOs).

RG 1.205 endorses the approach documented in NEI 04-02. Section 4.3.3 of NEI 04-02 states:

"The nuclear safety goal of NFPA 805 requires evaluation of the effects of a fire during any operational modes and plant configurations." Section 4.3.3 of NEI 04-02 goes on to provide a

• strategy that ..... demonstrate[s] that the nuclear safety performance criteria are met for High(er)

Risk Evolutions (HREs) (HREs as defined by Nuclear Management and Resources Council (NUMARC) 91-06) during non-power operational modes ... "

The staff will review the LAR to verify that the licensee has demonstrated that the nuclear safety performance criteria are met during HREs. One way to accomplish this objective is for the NRC staff to verify that the licensee has adequately documented the completion of the tasks in Appendix F to NEI 04-02.

NUMARC 91-06 discusses the development of outage plans and schedules. A key element of that process is to ensure SSCs that provide key safety functions (KSFs) perform as needed during the various outage evolutions. The results of the fire area analysis of those components relied upon to maintain DID should be factored into the plant's existing outage planning process.

In addition, for KSF equipment removed from service during the HREs, the impact should be evaluated based on KSF equipment status and the NPOs fire area assessment to develop needed contingency plans/actions. The NRC staff should review the licensee's process for ensuring the nuclear safety performance criteria are met during HREs.

\

111.4 RADIOACTIVE RELEASE PERFORMANCE CRITERIA NFPA 805 includes radioactive release goals, performance objectives, and performance criteria in paragraphs 1.3.2, 1.4.2, and 1.5.2. The staff will verify that the LAR documents that radiation release to any unrestricted area due to the direct effects of fire protection activities (but not involving fuel damage) remains as low as reasonable achievable, not to exceed the limits in 10 CFR Part 20. Appendix G to NEI 04-02 provides items for the reviewer to consider as part of this review.

111.5 RISK ASSESSMENTS AND PLANT CHANGE EVALUATIONS NFPA 805 requires risk assessments to be performed in several instances:

1. Plant Change Evaluations [NFPA 805 Section 2.4.4]

2. Additional risk associated with RAs [NFPA 805 Section 4.2.4]

3. Fire Risk Evaluations [NFPA 805 Section 4.2.4.2]

NRC staff review guidance for the risk assessments (1, 2 and 3 above) is provided in SRP paragraphs 111.5.3, 111.5.4, and 111.5.5, respectively.

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111.5.1 Fire PRA Technical Adequacy The staff will confirm the licensee has provided an evaluation of the technical adequacy of its PRA model consistent with RG 1.200 and SRP Section 19.2. The staff will confirm that the licensee has provided a description of its processes for assuring the PRA model is maintained and updated to reflect the as-built, as-operated and maintained plant, including operating experience of the plant.

The staff will review the licensee's assessment of the technical adequacy of the PRA model used for plant change evaluations required to transition to a RI/PB FPP and for any types of changes the licensee will be allowed to self-approve after implementation of the approved RI/PB FPP. The staff will review the maintenance and update process for the PRA model using SRP Section 19.1.

111.5.2 Defense-in-Depth and Safety Margins The staff will ensure that the licensee's plant change evaluations (Section 111.5.3 of this SRP) and fire risk evaluations (Section 111.5.5 of this SRP) ensure that the philosophy of DID is maintained relative to fire protection and nuclear safety. [NFPA 805 paragraph 2.4.4.2 and paragraph 4.2.4.2]

Fire protection DID is achieved when an adequate balance of each of the following elements is provided: [NPFA 805 paragraph 1.2]

(1) Preventing fires from starting (2) Rapidly detecting fires and controlling and extinguishing promptly those fires that do occur, thereby limiting fire damage (3) Providing an adequate level of fire protection for SSCs important to safety, so that a fire that is not promptly extinguished will not prevent essential plant safety functions from being performed Nuclear safety DID is achieved when an adequate balance of the following elements is provided: [SRP 19.2]

(1) Preventing core damage (2) Preventing containment failure (3) Mitigating consequence Consistency with the DID philosophy for fire protection and nuclear safety is maintained if the following acceptance guidelines, or their equivalent, are met:

• A reasonable balance is preserved among prevention of fires, early detection and suppression of fires, and the ability to achieve and maintain safe shut down of the plant post-fire.

9.5.1.2-16 Rev. 0 - January 2009

• A reasonable balance is preserved among prevention of core damage, prevention of containment failure, and mitigation of consequences.

• Over-reliance on programmatic activities to compensate for weaknesses in plant design is avoided.

• System redundancy, independence, and diversity are preserved commensurate with the

• expected frequency of challenges, consequences of failure of the system, and associated uncertainties.

• Defenses against potential common cause failures are preserved and the potential introduction of new common cause failure mechanisms is assessed.

• The independence of fission product barriers is not degraded.

• Defenses against human errors are preserved.

• The intent of the GDC of 10 CFR Part 50, Appendix A, is preserved.

The staff will ensure that the licensee's plant change evaluations ensure that sufficient safety margins are maintained. [NFPA 805 paragraph 2.4.4.3] With sufficient safety margins:

• Codes and standards or their alternatives approved for use by the NRC are met; and,

• Safety analysis acceptance criteria in the licensing basis are met, or proposed revisions provide sufficient margin to account for analysis and data uncertainty.

I Note that the deterministic approach in NFPA 805 for meeting the performance criteria shall be deemed to satisfy the DID and safety margins requirements. [NFPA 805 paragraphs 2.4.4.2 and 2.4.4.3]

111.5.3 Plant Change Evaluations Changes to a previously approved FPP element shall be evaluated with a plant change evaluation. NFPA 805 Section 2.4.4 states:

"A plant change evaluation shall be performed to ensure that a change to a previously approved fire protection program element is acceptable. The evaluation process shall consist of an integrated assessment of the acceptability of risk, defense-in-depth, and safety margins. The impact of the proposed change shall be monitored."

As applicable, plant change evaluations are required for transition to NFPA 805 as well as after implementation of the NFPA 805 FPP.

If required to address the acceptance guidance of RG 1.174 and SRP Section 19.2 (i.e., if any individual change or the overall change results in a risk increase above 1.0E-6/yr CDF, or 1.0E-7 large early release frequency (LERF)/yr), the staff will confirrn the licensee has provided the total CDF and LERF, i.e., risk contributions from internal and external events, including internal fires, to allow comparison with the acceptance guidelines of RG 1.174.

9.5.1.2-17 Rev. 0 - January 2009

The staff will review the licensee's plant change evaluations using the acceptance guidance of RG 1.174, and SRP Section 19.2. The staff should review any combined changes and cumulative risk as described in Section 111.5.6 below.

111.5.3.1 LAR to Implement NFPA 805 ("Transition')

The staff will verify that the LAR identifies all FPP non-compliances that the licensee does not intend to bring into deterministic compliance under NFPA 805. For each individual noncompliant item, the staff will confirm the licensee has provided a plant change evaluation which includes the following:

• Change in CDF and LERF comparing the non-compliant configuration to what would constitute a fully compliant deterministic configuration

• DID evaluation

• Safety margin evaluation In addition, the staff will confirm the licensee has provided the total change in CDF and LERF due to all non-compliances, including plant changes planned for the transition to NFPA 805.

This may also include credit for risk decreases due to retaining or making changes to fire protection features not required by NFPA 805, as permitted in RG 1.205 Section 2.2.

111.5.3.2 Plant Change Evaluations following NFPA 805 Implementation Once a licensee has implemented an FPP based on NFPA 805, some FPP changes will require prior NRC review and approval. The staff will review the plant change evaluation of these changes to ensure that the integrated assessment of risk, DID, and safety margins demonstrates that the change is acceptable. The staff will confirm the acceptability of the licensee's process for monitoring the impact of the change. For FPP changes that do not require NRC review and approval, the licensee will perform the plant change evaluation as approved by the NRC staff; see Section 111.1.3 of this SRP.

111.5.4 Risk of Crediting Recovery Actions NFPA 805 paragraph 4.2.4 states, in part: "When the use of recovery actions has resulted in the use of this approach, the additional risk presented by their use shall be evaluated." The staff will evaluate the licensee's definition of recovery action, how all human actions associated with mitigating fire initiated sequences have been evaluated and characterized, and the risk assessment of all RAs when used in lieu of deterministic requirements in NFPA 4.2.3. This risk evaluation may be qualitative per NFPA 805 paragraph 4.2.4.1 or quantitative per paragraph 4.2.4.2, and a bounding approach is acceptable. [RG 1.205 regulatory position 2.3]

111.5.5 Fire Risk Evaluations NFPA 805 paragraph 4.2.4.2 states in part: "Use of fire risk evaluation for the PB approach shall consist of an integrated assessment of the acceptability of risk, DID, and safety margins."

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The licensee must describe the change in risk for each, or each type, of alternative to the deterministic requirements of NFPA 805 in sufficient detail for the staff to be able to determine that the method is acceptable (a reference to a previously approved methodology would be sufficient if the licensee fully adopts such a methodology). The characterization of each change, or type of change, should include establishing a cause-effect relationship to identify portions of the PRA affected by the issue being evaluated. The results of the change in risk analyses should reflect this cause-effect relationship in a quantification of the impact on the PRA elements.

If the impacts of a change to the plant cannot be associated with elements of the PRA, the PRA should be modified accordingly or the impact of the change should be evaluated qualitatively as part of the integrated decision-making process. In any case, the effects of the changes on the reliability and unavailability of c or on operator actions should be appropriately accounted for in the risk assessment.

The staff will review the licensee's evaluation for any use of the PB approach in NFPA 805 paragraph 4.2.4.2 to ensure that the change in risk satisfies RG 1.174 acceptance guidelines and that DID and safety margins remain acceptable. The staff should review any combined changes and cumulative risk as described in Section 111.5.6 below.

111.5.6 Cumulative Risk and Combined Changes Section 2.4.4.1 of NFPA 805 requires licensees to evaluate the cumulative effect of plant changes (including all previous changes that have increased risk) on overall risk. The staff will review the licensee's evalu<¥ion of cumulative risk in accordance with the guidance in Section 3.3.2 of RG 1.174. For a transition LAR, cumulative risk is the total risk of transition. After transition to NFPA 805, the cumulative risk of further plant changes will be the change in risk between any future RIIPB changes and the fire CDF and LERF associated with the plant immediately after transition to NFPA 805. If the licensee includes a license condition permitting self approval of future changes to the FPP, the staff will verify that the proposed license condition limits the risk increase from any individual change such that there is reasonable assurance that the effect of self-approved changes on cumulative risk will be acceptable.

[RG 1.205 Section 3.2.6]

Section 2.4.4.1 further states that if more than one plant change is combined into a group for the purposes of evaluating acceptable risk, the evaluation of each individual change shall be performed along with the evaluation of combined changes. Any risk increases may be combined with risk decreases when estimating the total risk change. The staff will evaluate the licensee's combined changes as Combined Change Requests (CCRs) as described in RG 1.174 and SRP Section 19.2. RG 1.205 Section 3.2.6 provides guidance for combining changes.

111.6 MONITORING PROGRAM Section 2.6 of NFPA 805 requires licensees to establish and monitor acceptable levels of availability, reliability, and performance of fire protection systems and features. Monitoring methods are required to consider plant and industry operating experience. Ifthe established levels of availability, reliability or performance are not met, appropriate corrective actions to return to the established levels shall be implemented.

9.5.1.2-19 Rev. 0 - January 2009

The staff will review the licensee's proposed program to comply with these requirements.

111.7 PROGRAM DOCUMENTATION, CONFIGURATION CONTROL, AND QUALITY ASSURANCE Section 5 of NEI 04-02 provides guidanceto licensees regarding program documentation, configuration control, and quality assurance. This guidance is endorsed in RG 1.205.

111.7.1 Program Documentation Section 2.7.1 of NFPA 805 requires the licensee to adequately document compliance with the requirements in the standard, including establishment of an FPP design basis document. The NRC staff will verify that the licensee has established an FPP design basis document that meets the requirement of NFPA 805 Section 2.7.1.2.

III. 7.2 Configuration Control Section 2.7.2 of NFPA 805 requires the licensee to maintain configuration control of the design basis and supporting documents. The design basis document shall be kept up-to-date and maintained as a controlled document. Changes affecting the design, operation, or maintenance of the plant shall be reviewed by the licensee to determine if these changes impact the FPP documentation.

The NRC staff will review the licensee's process for maintaining configuration control of the FPP design basis document.

The acceptability of licensee's process for maintaining configuration control of the fire PRA methods and model is determined per Section 111.5.1 of this SRP.

111.7.3 Quality Section 2.7.3 of NFPA 805 establishes the quality requirements for each analysis, calculation, or evaluation performed in support of the LAR. These quality requirements are in the areas of independent review, V&V, personnel qualifications, and uncertainty analyses.

The NRC staff will verify that the licensee has established an FPP quality program that meets the requirements of NFPA Section 2.7.3. The staff will verify that the licensee has justified that fire models used are acceptable to the NRC. Note that the uncertainty analysis required by NFPA 805 Section 2.7.3.5 is not required to support deterministic approach calculations per 10 CFR 50.48(c)(2)(iv).

IV. EVALUATION FINDINGS The reviewer verifies that the applicant has provided sufficient information and that the review and calculations (if applicable) support conclusions similar to the following to be included in the staff's safety evaluation report:

9.5.1.2-20 Rev. 0 - January 2009

The staff concludes that the proposed LAR to implement an RI/PB FPP is acceptable and that the licensee has demonstrated that the resulting FPP will meet the requirements of GDC 3,10 CFR Parts 50.48(a) and 50.48(c). The staff has reviewed the licensee's analysis and justifications for the change and concludes that there is reasonable assurance that a fire in any plant area during any operational mode and plant configuration will not prevent the plant from achieving and maintaining the fuel in a safe and stable oondition.

The reviewer also states the bases for those conclusions.

V. IMPLEMENTATION The following is intended to provide guidance to applicants and licensees regarding the NRC staff's plans for using this SRP Section.

The staff will use this SRP section in performing safety evaluations of licensee requests to:

• Establish and maintain a FPP that complies with NFPA 805, as allowed by 10 CFR 50.48(c)(3)(i);

• Use PB methods permitted in NFPA 805 for the FPP elements and minimum design requirements of NFPA Chapter 3, as allowed by 10 CFR 50.48(c)(2)(vii);

• Use RI or PB alternatives to compliance with NFPA 805, as a~owed by 10 CFR 50.48(c)(4).

The staff will also use applicable portions of this SRP section in performing safety evaluations of licensee requests for any changes to its NFPA 805 FPP that must be submitted for prior approval.

The provisions of this SRP section apply to reviews of applications submitted six months or more after the date of issuance of this SRP section, unless superseded by a later revision.

VI. REFERENCES

1. 10 CFR Part 50, §50.12, "Specific exemptions"

2. 10 CFR Part 50, §50.34, "Contents of applications; technical information"

3. 10 CFR Part 50, §50.36, "Technical Specifications"

4. 10 CFR Part 50, §50.48, "Fire protection"

5. 10 CFR Part 50, §50.90, "Application for amendment of license or construction permit"

6. 10 CFR Part 50, §50.91, "Notice for public comment; State consultation"

7. 10 CFR Part 50, §50.92, "Issuance of amendment" 9.5.1.2-21 Rev. 0 - January 2009

8. 10 CFR Part 50, Appendix A, General Design Criterion 3, "Fire Protection"

9. 10 CFR Part 50, Appendix A, General Design Criterion 5, "Sharing of Structures, Systems, and Components"

10. 10 CFR Part 50, Appendix A, General Design Criterion 19, "Control Room"

11. 10 CFR Part 50, Appendix R, "Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1, 1979"

12. Branch Technical Position (BTP) SPLB 9.5-1, "Guidelines for Fire Protection for Nuclear Power Plants," USNRC (Formerly BTP CMEB 9.5-1) (ADAMS Accession No. ML070660454)

13. BTP APCSB 9.5-1, "Guidelines for Fire Protection for Nuclear Power Plants," USNRC, May 1,1976 (ADAMS Accession No. ML070660461)

14. BTP APCSB 9.5-1, Appendix A, "Guidelines for Fire Protection for Nuclear Power Plants Docketed Prior to July 1, 1976," USNRC (ADAMS Accession No. ML070660458)

15. Generic Letter 1986-10, "Implementation of Fire Protection Requirements," USNRC, April 24, 1986

16. Generic Letter 1986-10, Supplement 1, "Fire Endurance Test Acceptance Criteria for Fire Barrier Systems Used To Separate Redundant Safe-Shutdown Trains Within the Same Fire Area," USNRC, March 25, 1994

17. Generic Letter 2006-03, "Potentially Non-Conforming Hemyc and MT Fire Barrier Configurations," USNRC, April 10, 2006

18. NEI 00-01, "Guidance for Post-Fire Safe Shutdown Circuit Analysis," Revision 1, Nuclear Energy Institute, January 2005 (ADAMS Accession No. ML050310295)

19. NEI 04-02, "Guidance for Implementing a Risk-Informed, Performance-Based Fire Protection Program Under 10 CFR 50.48(c)," Revision 1, Nuclear Energy Institute, September 2005. (ADAMS Accession No. ML052590476)

20. NEI 07-12, "Fire Probabilistic Risk Assessment (FPRA) Peer Review Guidelines," Draft Version F, Revision 0, Nuclear Energy Institute, December 2007 (ADAMS Accession No. ML073551159)

21. NFPA 805, "Performance-Based Standard for Fire Protection for Light-Water Reactor Electric Generating Plants," National Fire Protection Association

22. NUREG-1600, "General Statement of Policy and Procedure for NRC Enforcement Actions, Interim Enforcement Policy May 1, 2000," USNRC

23. NUREG-1805, "Fire Dynamics Tools (FDTs) Quantitative Fire Hazard Analysis Methods for the U.S. Nuclear Regulatory Commission Fire Protection Inspection Program,"

USNRC, Washington, DC, December 2004 9.5.1.2-22 Rev. 0 - January 2009

24. NUREG-1824, "Verification and Validation of Selected Fire Models for Nuclear Power Plant Applications," Volumes 1-7, USNRC, May 2007

25. NUREG-1852, "Demonstrating the Feasibility and Reliability of Operator Manual Actions in Response to Fire," USNRC, October 2007

26. NUREG/CR-6850, "EPRI/NRC-RES, Fire PRA Methodology for Nuclear Power Facilities:" Volumes 1 and 2, USNRC, September 2005

27. Regulatory Guide 1.174, Revision 1, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," USNRC, November 2002 '

28. Regulatory Guide 1.189, Revision 2, "Fire Protection for Nuclear Power Plants," USNRC, issue date TBD

29. Regulatory Guide 1.200, Revision 2, "An Approach For Determining The Technical Adequacy Of Probabilistic Risk Assessment Results For Risk-Informed Activities,"

USNRC, issue date TBD

30. Regulatory Guide 1.205, "Risk-Informed, Performance-Based Fire Protection for Existing Light Water Nuclear Power Plants," USNRC, May 2006 (ADAMS Accession No. ML061100174)

31. Regulatory Issue Summary 2004-03, Revision 1, "Risk-Informed Approach for Post-Fire I Safe-Shutdown Associated Circuit Inspections," USNRC, December 29, 2004.

32. Regulatory Issue Summary 2005-07, "Compensatory Measures to Satisfy the Fire Protection Program Requirements," USNRC, April 19, 2005

33. Regulatory Issue Summary 2005-30, "Clarification of Post-Fire Safe-Shutdown Circuit Regulatory Requirements," USNRC, December 20, 2005

34. Regulatory Issue Summary 2006-10, "Regulatory Expectations with Appendix R Paragraph III.G.2 Operator Manual Actions," USNRC, June 30, 2006 1AII regulatory guides listed herein were published by the U.S. Nuclear Regulatory Commission. Most are available

. electronically through the Public Electronic Reading Room on the NRC's public Web site, at http://www.nrc.gov/

reading-rm/doc-collections/reg-guides/. Single copies of regulatory guides may also be obtained free of charge by writing the Reproduction and Distribution Services Section, ADM, USNRC, Washington, DC 20555-0001, or by fax to (301) 415-2289, or by email to DISTRIBUTION@nrc.gov. Active guides may also be purchased from the National Technicallnfonmation Service (NTIS) on a standing order basis. Details on this service may be obtained by contacting NTIS at 5285 Port Royal Road, Springfield, Virginia 22161, online at http://www.ntis.gov, by telephone at (800) 553-NTIS (6847) or (703)605-6000, or by fax to (703) 605-6900. Copies are also available for inspection or copying for a fee from the NRC's Public Document Room (PDR), which is located at 11555 Rockville Pike, Rockville, Maryland; the PDR's mailing address is USNRC PDR, Washington, DC 20555-0001. The PDR can also be reached by telephone at (301) 415A737 or (800) 397-4209, by fax at (301) 415-3548, and by email to PDR@nrc.gov.

9.5.1.2-23 Rev. 0 - January 2009

3S. Regulatory Issue Summary 2007-19, "Process for Communicating Clarifications of Staff Positions Provided in Regulatory Guide 1.20S Concerning Issues Identified during the Pilot Application of National Fire Protection Association Standard 80S," USNRC, August 20, 2007

36. NRC Office of Nuclear Reactor Regulation Office Instruction LlC-101, "License Amendments," USNRC, February 9, 2004. (ADAMS Accession No. ML0400602S8)

37. NRC Office of Nuclear Reactor Regulation Office Instruction LlC-109, "Acceptance Review Procedures," USNRC, May 2,2008 (ADAMS Accession No. ML081200811)

38. NRC Office of Nuclear Reactor Regulation Office Instruction LlC-111, "Regulatory Audits," USNRC, December 29,2008 (ADAMS Accession No. ML08290019S)

39. NRC Office of Nuclear Reactor Regulation Office Instruction LlC-SOO, "Processing Request for Reviews of Topical Reports," USNRC, June 24, 200S (ADAMS Accession No. MLOS18006S1)

VII. ATTACHMENTS

1. RIIPB FPP LAR Technical Acceptance Review Checklist for use with NRR Office Instruction LlC-109, "Acceptance Review Procedures" PAPERWORK REDUCTION ACT STATEMENT The infonnation collections contained in the Standard Review Plan are covered by the requirements of 10 CFR Part 50 and 10 CFR Part 52, and were approved by the Office of Management and Budget, approval number 3150-0011 and 3150-0151.

PUBLIC PROTECTION NOTIFICATION The NRC may not conduct or sponsor, and a person is not required to respond to, a request for information or an information collection requirement unless the requesting document displays a currently valid OMB control number.

9.S.1.2-24 Rev. 0 - January 2009

Attachment 1 - RIIPB FPP LAR Acceptance Review Matrix RI/PB FPP License Amendment Request Acceptance Review Matrix SRP III. Required Information Sufficient Comments for Review?

1.1 The LAR identifies any orders and license conditions that must be revised or superseded; I The LAR provides any necessary revisions to the plant's technical specifications and the bases thereof to implement a FPP that complies with NFPA 805.

The LAR includes a discussion of the changes to the Updated Final Safety Analysis Report (UFSAR) necessitated by the license amendment.

1.2 The LAR lists any plant modifications necessary to implement the RI/PB FPP; it includes description, a schedule, and justification, including compensatory measures until the modification is completed.

1.3 The LAR provides process for self-approving changes post-transition; including methods to be used. Ensure the followin~ are included in the LAR:

Licensee's process for self-approving changes post-transition The risk acceptance criteria in both CDF and LERF and any restrictions in terms of the types of changes that may be so implemented.

Licensee's approach to demonstrating that the fire PRA is technically adequate for the types of changes to be self-approved Licensee's PRA maintenance and update process to ensure that the PRA reflects the as-built, as-operated and maintained plant The method for ensuring adequate DID and safety mar~ins are maintained Allowed self-approval of NFPA 805 chapter 3 chan~es (optional) ______ -- -----

9.5.1.2-25 Rev. 0 - January 2009

RI/PB FPP License Amendment Request Acceptance Review Matrix SRP III. Required Information Sufficient Comments for Review?

Revised license condition, including self-approval if sou~ht 1.4 The LAR includes "no significant hazards consideration" 1.S The LAR includes a statement on environmental considerations 1.6 The LAR includes a transition schedule, justification for the schedule, and a list of modifications with a commitment to maintain in effect associated compensatory measures.

1.7 The LAR includes a request to use PB methods to establish compliance with the prescriptive fundamental FPP and design elements of Chapter 3 of NFPA 80S (10 CFR S0.48(c)(2)(vii) (if applicable) 1.8 The LAR includes a request to use RI or PB alternatives to demonstrate compliance with 10 CFR S0.48(c) (10 CFR S0.48(c)(4) (if applicable) 2 The LAR describes how the licensee complies with the fundamental FPP and design elements in Chapter 3 of NFPA 80S; the LAR describes the licensee's approach.

2.1 The LAR justifies use of the italicized exception in Section 3.6.4 of NFPA 80S per 10 CFR S0.48(c)(2)(vii) for water supply and distribution (if applicable) 2.2 The LAR identifies structures that comprise the "power block."

2.3 The LAR addresses electrical raceway fire barrier system issues (e.~., Hemyc and MT) if applicable.

3.1 The LAR describes the licensee's approach to establishing nuclear safety performance criteria and the results of implementin~ the approach.

9.S.1.2-26 Rev. 0 - January 2009

RI/PB FPP License Amendment Request Acceptance Review Matrix SRP III. Required Information Sufficient Comments*

for Review?

The LAR includes the engineering analyses required by NFPA 805, Section 2.4 The LAR documents the comparison of the existing FPP with the requirements of NFPA 805 The LAR summarizes the current licensing basis 3.1.1 inciudinQ the applicable regulatory requirements The LAR discusses use of feed-and-bleed for post fire 3.1.2 The LAR discusses flame propagation ratings of existing cables and the basis for the ratings and provides flame propagation ratings for new or replacement cables.

3.1.3 The LAR discusses fire-induced multiple spurious operations of equipment 3.2 The LAR evaluates each fire area for compliance to NFPA 805 requirements:

Description of use of the deterministic approach of NFPA 805 paragraph 4.2.3 are met, as applicable Documentation of previous NRC approval EEEEs that support deviations from the requirements and methods of NFPA 805 OMAs that will transition to recovery actions Description of use of the fire modeling approach of NFPA 805 paraQraph 4.2.4.1, as appropriate Statement that licensee has provided operational Quidance required by NFPA 805 4.2.4.1.6 Description of use of the fire risk approach of NFPA 805 paraQraph 4.2.4.2, as appropriate Description of use of RIIPB alternatives to NFPA 805 if approved (or approval requested) per 50.48(c)(4)

Compliance summary for each fire area, including identifyinQ fire hazards, reportinQ CDF and LERF 9.5.1.2-27 Rev. 0 - January 2009

RIIPB FPP License Amendment Request Acceptance Review Matrix SRP III. Required Information Sufficient Comments for Review?

values, identifying the significant core damage sequences and initiating events Exemptions, deviations, and EEEEs that the licensee desires to incorporate into the new IicensinQ basis 3.3 The LAR describes fire protection during NPOs and the procedures to address fire risk during these modes 4 The LAR describes how the radioactive release performance criteria are met 5.1 The LAR describes the fire PRA technical adequacy, including:

evaluation against appropriate standards process for PRA model maintenance/update technical adequacy for any NFPA 805 required risk assessments technical adequacy for any applications for which the licensee is requestinQ self-approval 5.2 The LAR describes how DID and safety margins are maintained.

5.3 The LAR includes plant change evaluations for non-

. compliances (based on current deterministic requirements) that the licensee does not intend to bring into deterministic compliance under NFPA 805 The LAR includes the total change in CDF and LERF due to all non-compliances, including plant changes planned for the transition to NFPA 805.

The LAR provides the total CDF and LERF, i.e., risk contributions from internal and external events, including internal fires (if required to address the acceptance guidance of RG 1.174 and SRP Section

• 19.2) 5.4 The LAR provides the risk of crediting recovery 9.5.1.2-28 Rev. 0 - January 2009

RIIPB FPP License Amendment Request Acceptance Review Matrix SRP III. Required Information Sufficient Comments for Review?

actions in lieu of meeting the deterministic requirements of NFPA 805 Section 4.2.3 5.5 The LAR includes fire risk evaluations per NFPA 805 Section 4.2.4.2 including an integrated assessment of the acceptability of risk, DID, and safety margins.

5.6 The LAR provides the cumulative risk if applicable.

The LAR provides the individual risk of changes when changes are combined into a group for the purposes of evaluating risk.

6 The LAR describes the proposed monitoring program to monitor acceptable levels of availability, reliability, and performance of fire protection systems and features 7.1 The LAR describes of the FPP design basis document 7.2 The LAR describes the configuration control process for the FPP design basis document 7.3 The LAR describes the program to ensure quality requirements are met 9.5.1.2-29 Rev. 0 - January 2009

..L U.5'" 1. VJ.""T Facility Info I Reading Rm I New I Help I Glossary I Contact Us Home> Electronic Reading Room> Document Collection. > NRC Regulations (10 CFR) > Part Index> § 50.48 Fire protection.

§ 50.48 Fire protection.

(a)(l) Each holder of an operating license issued under this part or a combined license issued under part 52 of this chapter must have a fire protection plan that satisfies Criterion 3 of appendix A to this part. This fire protection plan must:

(i) Describe the overall fire protection program for the facility; (ii) Identify the various positions within the licensee's organization that are responsible for the program; (iii) State the authorities that are delegated to each of these positions to implement those responsibilities; and (iv) Outline the plans for fire protection, fire detection and suppression capability, and limitation of fire damage.

(2) The plan must also describe specific features necessary to implement the program described in paragraph (a)(l) of this section such as--

(i) Administrative controls and personnel requiremel1ts for fire prevention and manual fire suppression activities; (ii) Automatic and manually operated fire detection and suppression systems; and (iii) The means to limit fire damage to structures, systems, or components important to safety so that the capability to shut down the plant safely is ensured.

(3) The licensee shall retain the fire protection plan and each change to the plan as a record until the Commission terminates the reactor license. The licensee shall retain each superseded revision of the procedures for 3 years from the date it was superseded.

(4) Each applicant for a design approval, design certification, or manufacturing license under part 52 of this chapter must have a description and analysis of the fire protection design features for the standard plant necessary to demonstrate compliance with Criterion 3 of appendix A to this part.

(b) Appendix R to this part establishes fire protection featlJres required to satisfy Criterion 3 of appendix A to this part with respect to certain generic issues for nuclear power plants licensed to operate before January 1, 1979.

(1) Except for the requirements of Sections III.G, I1I.J, and III.O, the provisions of Appendix R to this part do not apply to nuclear power plants licensed to operate before January 1, 1979, to the extent that--

(i) Fire protection features proposed or implemented by the licensee have been accepted by the NRC staff as satisfying the provisions of Appendix A to Branch Technical Position (BTP) APCSB 9.5-1 reflected in NRC fire protection safety evaluation reports issued before the effective date of February 19, 1981; or (ii) Fire protection features were accepted by the NRC staff in comprehensive fire protection safety evaluation reports issued before Appendix A to Branch Technical Position (BTP) APCSB 9.5-1 was published in August 1976.

(2) With respect to all other fire protection features covered by Appendix R, all nuclear power plants licensed to operate before January 1, 1979, must satisfy the applicable requirements of Appendix R to this part, including specifically the Enclosure 14 http://www.nrc.gov/reading-rmldoc-collections/cfr/part050/part050-0048.html 06/18/2010

10 CFR 50.48 Fire protection. Page 2 of4 requirements of Sections III.G, III.J, and III.O.

(c) National Fire Protection Association Standard NFPA 805.

(1) Approval of incorporation by reference. National Fire Protection Association (NFPA) Standard 805, "Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants, 2001 Edition" (NFPA 805), which is referenced in this section, was approved for incorporation by reference by the Director of the Federal Register pursuant to 5 U.S.c. 552(a) and 1 CFR part 51. Copies of NFPA 805 may be purchased from the NFPA Customer Service Department, 1 Batterymarch Park, P.O. Box 9101, Quincy, MA 02269-9101 and in PDF format through the NFPA Online Catalog (http://www.nfpa.org) or by calling 1-800-344-3555 or (617) 770-3000. Copies are also available for inspection at the NRC Library, Two White Flint North, 11545 Rockville Pike, Rockville, Maryland 20852-2738, and at the NRC Public Document Room, Building One White Flint North, Room 01-F15, 11555 Rockville Pike, Rockville, Maryland 20852-2738. Copies are also available at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call (202) 741-6030, or go to:

http://www.archives.gov/federaLregister/code_of_federaLregulations/ibr_locations.html.

(2) Exceptions, modifications, and supplementation of NFPA 805. As used in this section, references to NFPA 805 are to the 2001 Edition, with the following exceptions, modifications, and supplementation:

(i) Life Safety Goal, Objectives, and Criteria. The Life Safety Goal, Objectives, and Criteria of Chapter 1 are not endorsed.

(ii) Plant Damage/Business Interruption Goal, Objectives, and Criteria. The Plant Damage/Business Interruption Goal, Objectives, and Criteria of Chapter 1 are not endorsed.

(iii) Use offeed-and-bleed. In demonstrating compliance with the performance criteria of Sections 1.5.1(b) and (c), a high-pressure charging/injection pump coupled with the pressurizer power-operated relief valves (PORVs) as the sole fire-protected safe shutdown path for maintaining reactor coolant inventory, pressure control, and decay heat removal capability (i.e., feed-and-bleed) for pressurized-water reactors (PWRs) is not permitted.

(iv) Uncertainty analysis. An uncertainty analysis performed in accordance with Section 2.7.3.5 is not required to support deterministic approach calculations.

(v) EXisting cables. In lieu of installing cables meeting flame propagation tests as required by Section 3.3.5.3, a flame-retardant coating may be applied to the electric cables, or an automatic fixed fire suppression system may be installed to provide an equivalent level of protection. In addition, the italicized exception to Section 3.3.5.3 is not endorsed.

(vi) Water supply and distribution. The italicized exception to Section 3.6.4 is not endorsed. Licensees who wish to use the exception to Section 3.6.4 must submit a request for a license amendment in accordance with paragraph (c)(2)(vii) of this section.

(Vii) Performance-based methods. Notwithstanding the prohibition in Section 3.1 against the use of performance-based methods, the fire protection program elements and minimum design requirements of Chapter 3 may be subject to the performance-based methods permitted elsewhere in the standard. Licensees who wish to use performance-based methods for these fire protection program elements and minimum design requirements shall submit a request in the form of an application for license amendment under § 50.90. The Director of the Office of Nuclear Reactor Regulation, or a designee of the Director, may approve the application if the Director or designee determines that the performance-based approach; (A) Satisfies the performance goals, performance objectives, and performance criteria specified in NFPA 805 related to nuclear safety and radiological release; (B) Maintains safety margins; and (C) Maintains fire protection defense-in-depth (fire prevention, fire detection, fire suppression, mitigation, and post-fire safe shutdown capability).

(3) Compliance with NFPA 805.

htlp://www.mc.gov/reading-rmldoc-collections/cfr/part050/part050-0048.html 06/18/2010

• 10 CFR 50.48 Fire protection. Page 3 of4 (i) A licensee may maintain a fire protection program that complies with NFPA 805 as an alternative to complying with paragraph (b) of this section for plants licensed to operate before January 1, 1979, or the fire protection license conditions for plants licensed to operate after January 1, 1979. The licensee shall submit a request to comply with NFPA 805 in the form of an application for license amendment under § 50.90. The application must identify any orders and license conditions that must be revised or superseded, and contain any necessary revisions to the plant's technical specifications and the bases thereof. The Director of the Office of Nuclear Reactor Regulation, or a designee of the Director, may approve the application if the Director or designee determines that the licensee has identified orders, license conditions, and the technical specifications that must be revised or superseded, and that any necessary revisions are adequate. Any approval by the Director or the designee must be in the form of a license amendment approving the use of NFPA 805 together with any necessary revisions to the technical specifications.

(ii) The licensee shall complete its implementation of the methodology in Chapter 2 of NFPA 805 (including all required evaluations and analyses) and, upon completion, modify the fire protection plan required by paragraph (a) of this section to reflect the licensee's decision*to comply with NFPA 805, before changing its fire protection program or nuclear power plant as permitted by NFPA 805.

(4) Risk-informed or performance-based alternatives to compliance with NFPA 805. A licensee may submit a request to use risk-informed or performance-based alternatives to compliance with NFPA 805. The request must be in the form of an application for license amendment under § 50.90 of this chapter. The Director of the Office of Nuclear Reactor Regulation, or designee of the Director, may approve the application if the Director or designee determines that the proposed alternatives:

(i) Satisfy the performance goals, performance objectives, and performance criteria specified in NFPA 805 related to nuclear safety and radiological release; (ii) Maintain safety margins; and (iii) Maintain fire protection defense-in-depth (fire prevention, fire detection, fire suppression, mitigation, and post-fire safe shutdown capability).

(d) [Reserved].

(e) [Reserved].

(f) Licensees that have submitted the certifications required under § 50.82(a)(1) shall maintain a fire protection program to address the potential for fires that could cause the release or spread of radioactive materials (i.e., that could result in a radiological hazard). A fire protection program that complies with NFPA 805 shall be deemed to be acceptable for complying with the requirements of this paragraph.

(1) The objectives of the fire protection program are to--

(i) Reasonably prevent these fires from occurring; (ii) Rapidly detect, control, and extinguish those fires that do occur and that could result in a radiological hazard; and (iii) Ensure that the risk of fire-induced radiological hazards to the public, environment and plant personnel is minimized.

(2) The licensee shall assess the fire protection program on a regular basis. The licensee shall revise the plan as appropriate throughout the various stages of facility decommissioning.

(3) The licensee may make changes to the fire protection program without NRC approval if these changes do not reduce the effectiveness of fire protection for facilities, systems, and eqUipment that could result in a radiological hazard, taking into account the decommissioning plant conditions and activities.

[65 FR 38190, June 20, 2000; 69 FR 33550, June 16, 2004; 72 FR 49495, Aug. 28, 2007]

http://www.nrc.gov/reading-rmldoc-collections/cfr/part050/part050-0048.html 06118/2010

NUREG-0991

.trl$upplement NO.2***

Safety Evaluation Report related to the operation of Limerick Generating Station, Units 1 and 2 Docket Nos. 50-352 and 50-353 Philadelphia Electric Company U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation October 1984 Enclosure 15

9.5.1.2 Admininstrative Controls The administrative controls for fire protection consist of the fire protec-tion program and organization, the fire brigade training, the controls over combustibles and ignition sources, the prefire plans and procedures for fight-ing fires, and quality assurance. By letter dated February 21, 1984, the applicant committed to meet the guidelines in Section C.2 of BTP CMEB 9.5-1.

We find that, with this commitment, the administrative controls meet the guidelines in BTP CMEB 9.5-1, Item C.2, and are, therefore, acceptable.

9.5.1.3 Fire Brigade and Fire Brigade Training By FSAR Amendment 17, the applicant committed to meet the guidelines contained in BTP CMEB 9.5-1, Section C.3. We find that, with this commitment, fire brigade and fire brigade training meet BTP CMEB 9.5-1, Item C.3, and are, therefore, acceptable. Fire brigade training is evaluated in Section 13.2.2 of this report.

9.5.1.4 General Plant Guidelines 9.5.1.4.1 Building DeSign Fire areas are defined by walls and floor/ceiling assemblies. Walls that separate buildings and walls between rooms containing safe shutdown systems are 3-hour-fire-rated assemblies. In cases where the-fire rating is less than 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />, we have evaluated each area with respect to its fuel load, fire sup-pression and detection systems, and proximity to safe shutdown equipment and concluded that the fire-rated assemblies provided are adequate for the areas affected and meet the guidelines in Section C.5.a of BTP CMEB 9.5-1.

In some fire areas, the applicant did not provide protection of structural steel members which support fire rated assemblies in accordance with our guidelines.

By letter dated February 24, 1984, the applicant submitted an analysis which uses a mathematical model to calculate the time-temperature profile for poten-tial fires in each fire area.

If any of the calculations show that the time-temperature profile in an area will exceed 1100 0 F within 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />, an evaluation is performed to calculate the corresponding temperature response of the supporting structural steel. If the steel temperature exceeds 1100 0 F within 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />, the applicant has committed to protect the steel with 3-hour rated barriers where _possible; however, in some areas where congestion prevents the effective application of insulating materials to the structural steel, the applicant will provide an automatic sprinkler system as an alternative form of protection. If the steel temperature does not reach 110QoF, the steel will not need to be protected. We find these criteria will provide an adequate level of fire protection, and therefore find them an acceptable deviation from our guideline.

Our consultant, Brookhaven National Laboratory, has reviewed the applicant's analysis. Our consultant's report is included in Appendix M of this report.

We agree with our consultant that the analysis is acceptable.

Limerick SSER 2 9-6

The results of the analysis are summarized in Section 3 of the applicant's February 24, 1984 submittal. Of the 48 plant fire areas containing unprotected steel, three areas will be provided with insulation a'nd eight areas will be provided .with automatic sprinkler systems. We have reviewed the affected areas and conclude that the automatic sprinkler systems will provide adequate protec-tion of the steel by limiting any potential fire exposures and corresponding .

room temperature increases. There are 37 areas .where the steel is unprotected.

The applicant will provide penetration seals for all penetrations of fire-rated walls of floor/ceiling assemblies. The penetration seals have been subjected to qualification tests using the time-temperature curve specified by ASTM E-1l9, "Fire Test of Building Construction and Materials." By FPER Amendment 4, the applicant committed to utilize the acceptance criteria specified in our guidelines, which specify that the maximum temperature on the unexposed side of.the penetration seal should not exceed 325°F during the qualification test period.

By Amendment 6, the applicant informed us that the penetrations involving annu-lar pipe anchors did not meet the 325°F acceptance criteria. Annular pipe anchors are used.in the type of penetration involving a single pipe routed through a steel penetration sleeve that is embedded in a concrete wall. The pipe anchor consists of a steel plate spanning the annular space between the pipe and the penetration sleeve, and which is welded to both the pipe and the penetration sleeve over its entire circumference. Fire resistance for this type of penetration assembly is provided by installing mineral wool in the annular space to a minimum depth of 12 inches. This configuration has been tested for a 3-hour fire rating at the National Gypsum Company Research Center in cooperation with Factory Mutual Research. The assembly withstood the fire test and hose stream test with a maximum temperature of 425°F on the unexposed side of the annular anchor, measured at a location ,.1 inch from the surface of the pipe. This temperature is attributab1.e to heatConduction through the steel pipe.

Although the pipe anchors do not meet the specific ASTM E-1l9 temperature rise limitations, the test results Showed that the "fire would not spread to the unexposed side of a protected fire barrier during a 3-hour test period. We, therefore, have reasonable assuran-ce that the integrity and temperature trans-mission through the penetration assembly will not affect the capability to achieve and maintain safe shutdown considering the effects of a fire involving fixed and potential transient combustibles in the plant. This is in conformance with our guidelines in Section C.5.a of BTP CMEB 9.5-1, and is, therefore, acceptable.

The applicant is providing 2-hour-rated fire barriers for ~nclosed stairwells.

By FPER Amendment 4, the applicant stated that the stairwell enclosures would consist of 8-inch thick masonry walls with self-closing I-I/2-hour rated fire doors. This provides a level of safety consistent with our guidelines and, therefore, we find this acceptable.

In Amendment 6, the applicant stated that except for steamtight, watertight, missile resisting and oversize doors,* the door openings in fire-rated barriers are provided with Underwriters. Laboratory (UL)-labeled fire door assemblies that have ratings commensurate with the fire ratings of the walls in which they Li meri ck SSER 2 9-7

located on the north side of the turbine building, within 14 feet of the build-ing exterior wall. No safety-related equipment is located* within the turbine building. The turbine building exterior walls are not rated. The transformers are protected by an automatic water deluge system. We find this an acceptable deviation from the guidelines of BTP CMEB 9.5-1, Section C.S.a, because no safety-related equipment is located in the turbine building. We conclude that the installation of the transformers, with the approved deviation, meets the guidelines of BTP CMEB 9.5-1, Sections C.5.a.12 and 13, and is, therefore, acceptable.

Floor drains are provided for the majority of plant areas. Floor drains are not provided for the 4-kV switchgear compartment, and the static inverter compartments. By FPER Amendment 4, the applicant provided an analysis showing that redundant trains of safety-related equipment in unaffected areas would not be flooded by excess fire fighting water. .

Based on our review, we conclude that the location of floor drains will meet the guidelines of Section C.S.a.14 of BTP CMEB 9.S-1, and is, therefore, acceptable.

Based on our evaluation, we conclude that the building design, wHh the approved deviations, meets our guidelines in Section C.S.a of BTP CMEB 9.S-1 and is, therefore, acceptable.

9.S.1.4.2 Safe Shutdown Capability As part of the FSAR submittal, the applicant provided a report on safe shutdown capability following a fire, in accordance with the requirements of Appendix R (BTP CMEB 9.5-1, Section C.S.b). Further discussion of the safe shutdown capa-bility, including information on cable separation and safe shutdown equipment location, is in FSAR Section 9,S.

The applicant's safe shutdown analysis states that systems needed for hot shut-down and cold shutdown are redundant and that one of the redundant systems needed for'safe shutdown would be kept free of fire damage through separation, fire barriers, and/or alternative shutdown capability. To achieve hot shutdown either the reactor core isolation cooling system or the high pre*ssure coolant injection system would be available, in addition to the main steam isolation and safety relief valves, automatic depressurization system valves, the residual heat removal (RHR) system loop A or B, the RHR service. water (RHRSW) system loop A or B, and the emergency service water (ESW) system loop A or B. Going to cold shutdown from hot shutdown would require the A loops of the RHR, RHRSW, and the ESW or the B loops of the RHR, RHRSW, and ESW. The safe shutdown review considered components; cabling, and support equipment for systems iden-tified above that are needed to achieve shutdown .. The applicant has provided a cable separation review for all rooms of the plant housing safe shutdown equipment to ensure that at least one train of this equipment is available in the event of a fire in any of these rooms. The review identified the safety-related equipment and redundant safe shutdown system cabling and dhcussed the consequences of a fire in each of these rooms. We have reviewed the applicant's deterministic review of the plant and conclude that it provides an acceptable means of demonstrating that separation exists between redundant safe shutdown trains.

Limerick SSER 2 9-9

The applicant's review divided the areas by the diesel generator electrical division. Cables and equipment were considered disabled in the area of the fire unless the fire hazards analysis assumed otherwise. No repairs were assumed. The applicant has also identified that alternative shutdown is required for the control room. If fire disables the control room, a remote shutdown panel located in a separate fire protected room in the control structure is provided as an alternative to providing fire protection. The remote shutdown panel is electrically isolated from the control room. (See Section 9.5.1.4.2 below for further discussion on the alternative shutdown capabil ity.)

We reviewed the means of separation proposed to ensure that one train of cables and equipment needed to safely shutdown the plant will be maintained free of fire damage.

We identified twelve areas where this separation was not provided. By Amendment 3, the applicant committed to meet our guidelines for the following areas:

(1) Fire Area 2, 13-kV switchgear area (2) Fire Area 7, corridor el 239 feet (3) Fire Area 12, Unit 1, 4-kV switchgear area (4) Fire Area 20, Unit 1, static inverter compartment (5) Fire Area 25, auxiliary equipment room (6) Fi re Area 27, control structure fan room (7) Fi re Area 40, corridor el 177 feet (8) Fire Area 43, safeguard system isolation valve area By Amendment 5, the applicant revised his commitment for fire area 43. This area will be provided with a separation boundary consisting of 20 feet free of intervening combustibles. We have reviewed the change and concluded that because of the low combustible loading in the area, this is an acceptable deviation to Section.C.5.b of BTP CMEB 9.5-1.

The applicant, by Amendment 4, committed to provide a separation boundary between redundant trains, consisting of 20 feet free of intervening combusc

. tibles and a water curtain for the following three areas:

(1) . Fi re *Area 44, safeguard system access area (2) Fire Area 45, CRO hydraulic equipment area and neutron monitoring system area (3) Fire Area 48, RWCU holding pump compartments, RERS fan area and corridors Limerick SSER 2 9-10

Due to the low combustible loading, and configuration of redundant cable in these areas, we find this level of protection acceptable.

In our SER, we incorrectly stated that the applicant had also committed to provide a water curtain for Fire Area 47, RWCU compartments, fuel pool cooling and cleanup (FPCC) compartment, and general equipment area. The components associated with the different shutdown methods are located on opposite sides of the primary containment, such that their horizontal separation is greater than 100 feet, and the only combustible materials in the intervening space are electrical cables in cable trays. A 20-foot-wide- zone that is free of combustibles will be maintained between the method A and method B components.

No cable trays are located within this combustible-free zone. The combustible-free zone divides the fire area into a western portion and an eastern portion.

We have evaluated this area and conclude that because of the low combustible loading, configuration of cables and their location at the ceiling level, an automatic suppression would not greatly enhance the level of fire protection safety. We find this an acceptable deviation from Section C.5.b of BTP CMEB 9.5-1, and is, therefore, acceptable.

We noted that two redundant load centers which are located on the 313' ele-vation of the reactor building (Fire Area 48) are approximately 35 feet apart.

It was our concern that because water curtain is located at the ceiling and is manually operated, a considerable time delay could occur before the heat from a floor-based exposure fire would be dissipated. In this time period, both load centers could be damaged.

By FPER Amendment 6, the applicant committed to ,provide a radiant energy shield between the load centers because the radiant energy shield will prevent a floor-based exposure fire from damaging the load centers until the sprinklers are activated. We find this an. acceptable deviation from Section C.5.b of BTP CMEB 9.5-1, and is, therefore, acceptable.

During our site audit, we noted that a ventilation duct is prov_ided to serve both the remote shutdown panel area, and the adjacent auxiliary equipment room.

The remote panel provides alternative shutdown for some of the functions in the auxiliary equipment room. It was our concern that a fire in the auxiliary equipment room could cause smoke and other products of combustion to enter the remote panel area.

By FPER Amendment 6, the applicant committed to modify the HVAC system so that the remote shutdown panel room is maintained at a positive pressure, thereby preventing the infiltration of smoke. We find this acceptable.

Based on our review, we conclude that, with the accepted deviations, the fire protection for safe shutdown meets our guidelines in Section C.5.b of BTP CMEB 9.5-1, and is,-therefore, acceptable.

9.5.1.4.3 Alternate Shutdown FSAR Section 7.4.1.4 describes the design and capab'ility of the remote shutdown panel. The present design objective of the remote shutdown panel is to aChieve _

and maintain cold shutdown in the event of an evacuation as a result of a 'fire that disables the control room. The reactor core isolation cooling (RCIC)

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system, safety/relief valves (SRVs), and one division of the residual heat re-moval (RHR) system, RHR service water (RHRSW) system, and the emergency service water (ESW) system can be controlled from the remote shutdown panel to achieve cold shutdown should a fire disable the control room. lo ensure the availability of this remote .shutdown panel in the event of a control room fire, transfer switches are provided to transfer to the remote shutdown panel enough equipment to provide the capability to go to cold shutdown. These transfer switches provide electrical isolation between the control room and the remote shutdown panel.

The design of the remote shutdown panel complies with the performance goals outlined in the requirements of Section III.l of Appendix R (BlP CMEB 9.5-1, Section C.5.c). Reactivity control will be* accomplished by a manual scram before the operator leaves the control room. The RCIC system will provide reactor coolant makeup, and the RHR system and the SRVs will be used for reactor decay heat removal. Reactor vessel water level, reactor vessel pres-sure, suppression pool water level and temperature, RCIC pump turbine sp*eed, and RHR system flow are among the instrumentation available at the remote shut-down panel to provide direct reading of process variables. The remote shutdown panel will also *include instrumentation and control of support functions needed for the shutdown equipment.

We evaluated the fire protection provided for the remote shutdown panel and conclude that it is not physically separated from the control room in accord-ance with the guidelines in Section C.5.c of BTP CMEB 9.5-1. The remote shut-down panel is located in the auxiliary equipment room (Fire Area 25), along with. power generation control complex (PGCC) cabinets, and, therefore, this".

area contains systems for both the normal shutdown system and the alternate shutdown capability for both units. By Amendment 4, the applicant committed to enclose the remote shutdown panel in a separate 3-hour-rated enclosure.

We find that, with this commitment, the fire protection provided for the alternate shutdown panel will meet the guidelines of Section C.5.c of BTP CHEB 9.5-1 and is, therefore, acceptable.

9.5.1.4.4 Control of Combustibles*

Safety-related systems have been isolated or separated from combustible mate-rials as much as possible. The storage of flammable liquids complies with Standard 30 of the National Fire Protection Association (NFPA 30). Compressed gases are stored either outdoors or in nonsafety-related structures whenever possible. However,*compressed gas cylinders associated with the primary containment instrument gas system and containment combustible gas monitoring system are located in the reactor enclosure.

By FPER Amendment 4, the applicant stated that the primary. containment instru-ment gas system utilizes cylinders of nitrogen and a nitrogen/hydrogen mixture.

The mixture of gases contain 5% hydrogen. If this quantity o.f hydrogen were inadvertently released, the resultant gas would be diluted to below 4% hydrogen, the lower flammable limit (lFl).. Because the quantity of hydrogen will remain below the lFl, during a leak, we find this acceptable.

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We find that, the storage of flammable compressed gases will meet the guide-lines of Section C.5.d of BTP CMEB 9.5-1 and is, therefore, acceptable.

The hydrogen piping in safety-related areas has been designed to seismic Cate-gory I. requirements. Based on its evaluation, the NRC staff concludes that the design of hydrogen piping meets the guidelines of Section C.5.d.5 of BTP CMEB 9.5-1 and is, therefore, acceptable.

9.5.1.4.5 Electrical Cable Construction, Cable Trays, and Cable Penetrations Cable trays are of all metal construction. Electrical cable construction generally passes the IEEE 383-1974 flame test. Only lighting and communica-tions cables do not pass this test. However, because these cables are routed exclusive in conduit and are not routed with cables for safety-related systems we find this acceptable. The cables are designed to allow wetting down with fire suppression water without electrical faulting.

Safety-related cable trays outside the cable spreading room are not provided with continuous line-type heat detectors. Instead, smo~e detectors of the ionization or photo-electric type are located in areas through which safety-related cable trays are routed. This method of detection .has been selected in lieu of line-type heat detectors because the products of combustion will be detected by the smoke detectors earlier than the heat from a faulted cable would be detected by heat detectors. Because of the increased sensitivity of the ionization detectors, we find this acceptable.

By letter dated November 23, 1983 and February 16, 1984, the applicant identi-fied those areas containing concentrations of cable trays that will be protected*

by Automatic Suppression Systems.

We have evaluated these areas and agree with the licensee that the configura-tion of combustibles in these area represent a hazard of sufficient magnitude to warrant the addition of automatic suppression.

Based on our review, we conclude that the protection provided for Electrical Cable Construction, Cable Trays, and Cable Penetration meets our guidelines in .

Section C.5.e of BTP CMEB 9.5-1, and is, therefore, acceptable.

9.5.1.4.6 Ventilation There are*no ventilation systems in the plant designed specifically to exhaust smoke or other products of combustion. Normal plant ventilation systems will be utilized for this purpose. Portable. smoke ejectors will be provided to assist in removal of the products of combustion should the normal ventilation systems be unavailable because of damper closures or other failures. Because the normal ventilation system is capable of being realigned to 100% exhaust, we find this acceptable. The power supply and controls for the ventilation systems for the control structure fan rooms are not run outside the fire area served by the system. By FPER Amendment 4, the applicant committed to separate the redundant trains of power supply and control cables by greater than 20 feet. In addition, automatic suppression and detection will be provided. We find this acceptable.

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