Notice of Opportunity To Comment on Model Safety Evaluation on Technical Specification Improvement for Boiling Water Reactor Plants; to Risk-Inform Requirements Regarding Selected Required Action End States Using the Consolidated Line Item Improvement Process, 74037-74055 [05-24021]

Download as PDF Federal Register / Vol. 70, No. 239 / Wednesday, December 14, 2005 / Notices MATTERS TO BE CONSIDERED: Week of December 12, 2005 Monday, December 12, 2005 8:50 a.m. Affirmation Session (Public Meeting) (Tentative). a. Exelon Generation Company, LLC (Early Site Permit for Clinton Site) (Tentative) 9:00 a.m. Discussion of Security Issues (closed—ex. 1) Wednesday, December 14, 2005 2:00 p.m. Discussion of Security Issues (closed—ex. 1) Thursday, December 15, 2005 1:30 p.m. Briefing on Threat Environment Assessment (closed—ex. 1) Week of December 19, 2005—Tentative There are no meetings scheduled for the Week of December 19, 2005. Week of December 26, 2005—Tentative There are no meetings scheduled for the Week of December 26, 2005. Week of January 2, 2006—Tentative There are no meetings scheduled for the Week of January 2, 2006. Week of January 9, 2006—Tentative Tuesday, January 10, 2006 9:30 a.m. Briefing on International Research and Bilateral Agreements. (Contact: Roman Shaffer, 301–415– 7606.) This meeting will be webcast live at the Web address http://www.nrc.gov. Wednesday, January 11, 2006 9:30 a.m. Meeting with Advisory Committee on Nuclear Waste (ACNW). (Contact: John Larkins, 301– 415–7360.) This meeting will be webcast live at the Web address http://www.nrc.gov. Thursday, January 12, 2006 9:30 a.m. Discussion of Security Issues (closed—ex. 1 & 2) Week of January 16, 2006—Tentative Thursday, January 19, 2006 1:30 p.m. Discussion of Security Issues (closed—ex. 1) *The schedule for Commission meetings is subject to change on short notice. To verify the status of meetings call (recording)—(301) 415–1292. Contact person for more information: Michelle Schroll, (301) 415–1662. * * * * * The NRC Commission Meeting Schedule can be found on the Internet VerDate Aug<31>2005 15:29 Dec 13, 2005 Jkt 208001 at: http://www.nrc.gov/what-we-do/ policy-making/schedule.html. * * * * * ADDITIONAL INFORMATION: By a vote of 4– 1 on December 7, the Commission determined pursuant to U.S.C. 552b(e) and § 9.107(a) of the Commission’s rules that ‘‘Discussion of International Issues (closed—ex. 9)’’ be held December 8, and on less than one week’s notice to the public. * * * * * The NRC provides reasonable accommodation to individuals with disabilities where appropriate. If you need a reasonable accommodation to participate in these public meetings, or need this meeting notice or the transcript or other information from the public meetings in another format (e.g. braille, large print), please notify the NRC’s Disability Program Coordinator, August Spector, at 301–415–7080, TDD: 301–415–2100, or by e-mail at aks@nrc.gov. Determinations on requests for reasonable accommodation will be made on a case-by-case basis. * * * * * This notice is distributed by mail to several hundred subscribers; if you no longer wish to receive it, or would like to be added to the distribution, please contact the Office of the Secretary, Washington, DC 20555 (301–415–1969). In addition, distribution of this meeting notice over the Internet system is available. If you are interested in receiving this Commission meeting schedule electronically, please send an electronic message to dkw@nrc.gov. 74037 AGENCY: changes to end state requirements for required actions in Boiling Water Reactor (BWR) plants’ technical specifications (TS). The NRC staff has also prepared a model no-significanthazards-consideration (NSHC) determination relating to this matter. The purpose of these models is to permit the NRC to efficiently process amendments that propose to adopt technical specifications changes, designated as TSTF–423, related to Topical Report GE NEDC–32988, Revision 2, ‘‘Technical Justification to support Risk Informed Modification to Selected Required Action End States for BWR Plants,’’ which was approved by an NRC SE dated September 27, 2002. Licensees of BWR nuclear power reactors to which the models apply could then request amendments, confirming the applicability of the SE and NSHC determination to their reactors. The NRC staff is requesting comment on the model SE and model NSHC determination prior to announcing their availability for referencing in license amendment applications. DATES: The comment period expires January 13, 2006. Comments received after this date will be considered if it is practical to do so, but the Commission is able to ensure consideration only for comments received on or before this date. ADDRESSES: Comments may be submitted either electronically or via U.S. mail. Comments may be submitted by electronic mail to CLIIP@nrc.gov. Submit written comments to Chief, Rules and Directives Branch, Division of Administrative Services, Office of Administration, Mail Stop: T–6 D59, U.S. Nuclear Regulatory Commission, Washington, DC 20555–0001. Hand deliver comments to: 11545 Rockville Pike, Rockville, Maryland, between 7:45 a.m. and 4:15 p.m. on Federal workdays. Copies of comments received may be examined at the NRC’s Public Document Room, 11555 Rockville Pike (Room O– 1F21), Rockville, Maryland. FOR FURTHER INFORMATION CONTACT: T. R. Tjader, Mail Stop: O–12H2, Division of Inspection and Regional Support, Office of Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, Washington, DC 20555–0001, telephone 301–415–1187. SUPPLEMENTARY INFORMATION: SUMMARY: Notice is hereby given that the staff of the Nuclear Regulatory Commission (NRC) has prepared a model safety evaluation (SE) relating to Background Regulatory Issue Summary 2000–06, ‘‘Consolidated Line Item Improvement Process for Adopting Standard Technical Specification Changes for Power Reactors,’’ was issued on March Dated: December 8, 2005 R. Michelle Schroll, Office of the Secretary. [FR Doc. 05–24064 Filed 12–12–05; 12:07 pm] BILLING CODE 7590–01–M NUCLEAR REGULATORY COMMISSION Notice of Opportunity To Comment on Model Safety Evaluation on Technical Specification Improvement for Boiling Water Reactor Plants; to Risk-Inform Requirements Regarding Selected Required Action End States Using the Consolidated Line Item Improvement Process Nuclear Regulatory Commission. ACTION: Request for comment. PO 00000 Frm 00050 Fmt 4703 Sfmt 4703 E:\FR\FM\14DEN1.SGM 14DEN1 74038 Federal Register / Vol. 70, No. 239 / Wednesday, December 14, 2005 / Notices 20, 2000. The consolidated line item improvement process (CLIIP) is intended to improve the efficiency of NRC licensing processes, by processing proposed changes to the standard technical specifications (STS) in a manner that supports subsequent license amendment applications. The CLIIP includes an opportunity for the public to comment on proposed changes to the STS after a preliminary assessment by the NRC staff and finding that the change will likely be offered for adoption by licensees. The CLIIP directs the NRC staff to evaluate any comments received for a proposed change to the STS and to either reconsider the change or announce the availability of the change for adoption by licensees. Licensees opting to apply for this TS change are responsible for reviewing the staff’s evaluation, referencing the applicable technical justifications, and providing any necessary plant-specific information. Each amendment application made in response to the notice of availability will be processed and noticed in accordance with applicable NRC rules and procedures. This notice solicits comment on changes to end state requirements for required actions, if risk is assessed and managed, for the primary purpose of accomplishing short-duration repairs which necessitated exiting the original Mode of operation. The change was proposed in Topical Report GE NEDC– 32988, Revision 2, ‘‘Technical Justification to support Risk Informed Modification to Selected Required Action End States for BWR Plants,’’ which was approved by an NRC SE dated September 27, 2002. This change was proposed for incorporation into the standard technical specifications by the owners groups participants in the Technical Specification Task Force (TSTF) and is designated TSTF–423. TSTF–423 can be viewed on the NRC’s Web page at http://www.nrc.gov/ reactors/operating/licensing/ techspecs.html. Applicability This proposal to modify technical specification requirements by the adoption of TSTF–423 is applicable to all licensees of BWR plants who have adopted or will adopt, in conjunction with the proposed change, technical specification requirements for a Bases control program consistent with the TS Bases Control Program described in Section 5.5 of the applicable vendor’s STS. To efficiently process the incoming license amendment applications, the staff requests that each licensee applying for the changes proposed in VerDate Aug<31>2005 15:29 Dec 13, 2005 Jkt 208001 TSTF–423 include Bases for the proposed TS consistent with the Bases proposed in TSTF–423. In addition, licensees that have not adopted requirements for a Bases control program by converting to the improved STS or by other means, are requested to include the requirements for a Bases control program consistent with the STS in their application for the proposed change. The need for a Bases control program stems from the need for adequate regulatory control of some key elements of the proposal that are contained in the proposed Bases in TSTF–423. The staff is requesting that the Bases be included with the proposed license amendments in this case because the changes to the TS and the changes to the associated Bases form an integral change to a plant’s licensing bases. To ensure that the overall change, including the Bases, includes appropriate regulatory controls, the staff plans to condition the issuance of each license amendment on the licensee’s incorporation of the changes into the Bases document and on requiring the licensee to control the changes in accordance with the Bases Control Program. The CLIIP does not prevent licensees from requesting an alternative approach or proposing the changes without the requested Bases and Bases control program. However, deviations from the approach recommended in this notice may require additional review by the NRC staff and may increase the time and resources needed for the review. Public Notices This notice requests comments from interested members of the public within 30 days of the date of publication in the Federal Register. After evaluating the comments received as a result of this notice, the staff will either reconsider the proposed change or announce the availability of the change in a subsequent notice (perhaps with some changes to the safety evaluation or the proposed NSHC determination as a result of public comments). If the staff announces the availability of the change, licensees wishing to adopt the change must submit an application in accordance with applicable rules and other regulatory requirements. For each application, the staff will publish a notice of consideration of issuance of amendment to facility operating licenses, a proposed NSHC determination, and a notice of opportunity for a hearing. The staff will also publish a notice of issuance of an amendment to operating license to announce the modification of end state requirements for required actions in plant technical specifications. PO 00000 Frm 00051 Fmt 4703 Sfmt 4703 Proposed Model Plant Specific Safety Evaluation for Technical Specification Task Force (TSTF) Change TSTF–423, Risk Informed Modification to Selected Required Action End States, a Consolidated Line Item Improvement Safety Evaluation by the Office of Nuclear Reactor Regulation; Related to Amendment No. [ll] to Facility Operating License NFP–[ll], [Utility Name], [Plant Name], [Unitll], Docket No.–[ll] 1.0 Introduction By letter dated llll, 20 l, [Utility Name] (the licensee) proposed changes to the technical specifications (TS) for [plant name]. The requested changes are the adoption of TSTF–423, Revision 0, to the Boiling Water Reactor (BWR) Standard Technical Specifications (STS) (NUREG 1433 and NUREG 1434), which was proposed by the Nuclear Energy Institute (NEI) Risk Informed Technical Specifications Task Force (RITSTF) on August 12, 2003, on behalf of the industry. TSTF–423, Revision 0, incorporates the BWR Owners Group (BWROG) approved Topical Report NEDC–32988, Revision 2, ‘‘Technical Justification to Support Risk Informed Modification to Selected Required Action End States for BWR Plants’’ (Reference 1), into the BWR STS (Note: The changes are made with respect to Revision 2 of the STS NUREGs). TSTF–423 is one of the industry’s initiatives developed under the Risk Management Technical Specifications (RMTS) program. These initiatives are intended to maintain or improve safety through the incorporation of risk assessment and management techniques in TS, while reducing unnecessary burden and making TS requirements consistent with the Commission’s other risk-informed regulatory requirements, in particular the maintenance rule. The Code of Federal Regulations, 10 CFR 50.36, ‘‘Technical Specifications,’’ states: ‘‘When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow the remedial action permitted by the technical specification until the condition can be met.’’ The STS and many plant TS provide a completion time (CT) for the plant to meet the limiting condition for operation (LCO). If the LCO or the remedial action cannot be met, then the reactor is required to be shut down. When the STS and individual plant technical specifications were written, the shutdown condition or end state specified was usually cold shutdown. E:\FR\FM\14DEN1.SGM 14DEN1 Federal Register / Vol. 70, No. 239 / Wednesday, December 14, 2005 / Notices Topical Report NEDC–32988, Revision 2, provides the technical basis to change certain required end states when the TS Actions for remaining in power operation cannot be met within the CTs. Most of the requested TS changes permit an end state of hot shutdown (Mode 3), if risk is assessed and managed, rather than an end state of cold shutdown (Mode 4) contained in the current TS. The request was limited to those end states where: (1) Entry into the shutdown mode is for a short interval, (2) entry is initiated by inoperability of a single train of equipment or a restriction on a plant operational parameter, unless otherwise stated in the applicable TS, and (3) the primary purpose is to correct the initiating condition and return to power operation as soon as is practical. The STS for BWR plants define five operational modes. In general, they are: • Mode 1—Power Operation. The reactor mode switch is in run position. • Mode 2—Reactor Startup. The reactor mode switch is in refuel position (with all reactor vessel head closure bolts fully tensioned) or in startup/hot standby position. • Mode 3—Hot Shutdown. The reactor coolant system (RCS) temperature is above 200 degrees F (TS specific) and the reactor mode switch is in shutdown position (with all reactor vessel head closure bolts fully tensioned). • Mode 4—Cold Shutdown. The RCS temperature is equal to or less than 200 degrees F and the reactor mode switch is in shutdown position (with all reactor vessel head closure bolts fully tensioned). • Mode 5—Refueling. The reactor mode switch is in shutdown or refuel position, and one or more reactor vessel head closure bolts are less than fully tensioned. Criticality is not allowed in Modes 3 through 5. TSTF–423 generally allows a Mode 3 end state rather than a Mode 4 end state for selected initiating conditions in order to perform short-duration repairs which necessitate exiting the original Mode of operation. Short duration repairs are on the order of 2- to 3-days, but not more than a week. 2.0 Regulatory Evaluation In 10 CFR 50.36, the Commission established its regulatory requirements related to the content of TS. Pursuant to 10 CFR 50.36(c), TS are required to include items in the following five specific categories related to station operation: (1) Safety limits, limiting safety system settings, and limiting control settings; (2) limiting conditions VerDate Aug<31>2005 15:29 Dec 13, 2005 Jkt 208001 for operation (LCOs); (3) surveillance requirements (SRs); (4) design features; and (5) administrative controls. The rule does not specify the particular requirements to be included in a plant’s TS. As stated in 10 CFR 50.36(c)(2)(i), the ‘‘Limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications * * *.’’ Reference 1 states: ‘‘Cold shutdown is normally required when an inoperable system or train cannot be restored to an operable status within the allowed time. Going to cold shutdown results in the loss of steam-driven systems, challenges the shutdown heat removal systems, and requires restarting the plant. A more preferred operational mode is one that maintains adequate risk levels while repairs are completed without causing unnecessary challenges to plant equipment during shutdown and startup transitions.’’ In the end state changes under consideration here, a problem with a component or train has or will result in a failure to meet a TS, and a controlled shutdown has begun because a TS Action requirement cannot be met within the TS CT. Most of today’s TS and the design basis analyses were developed under the perception that putting a plant in cold shutdown would result in the safest condition and the design basis analyses would bound credible shutdown accidents. In the late 1980s and early 1990s, the NRC and licensees recognized that this perception was incorrect and took corrective actions to improve shutdown operation. At the same time, standard TS were developed and many licensees improved their TS. Since enactment of a shutdown rule was expected, almost all TS changes involving power operation, including a revised end state requirement, were postponed (see, for example the Final Policy Statement on TS Improvements, Reference 2). However, in the mid 1990s, the Commission decided a shutdown rule was not necessary in light of industry improvements. Controlling shutdown risk encompasses control of conditions that can cause potential initiating events and responses to those initiating events that do occur. Initiating events are a function of equipment malfunctions and human error. Responses to events are a function of plant sensitivity, ongoing activities, human error, defense-in-depth, and additional equipment malfunctions. PO 00000 Frm 00052 Fmt 4703 Sfmt 4703 74039 In practice, the risk during shutdown operations is often addressed via voluntary actions and application of 10 CFR 50.65 (Reference 3), the maintenance rule. Section 50.65(a)(4) states: ‘‘Before performing maintenance activities * * * the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. The scope of the assessment may be limited to structures, systems, and components that a riskinformed evaluation process has shown to be significant to public health and safety.’’ Regulatory Guide (RG) 1.182 (Reference 4) provides guidance on implementing the provisions of 10 CFR 50.65(a)(4) by endorsing the revised Section 11 (published separately) to NUMARC 93–01, Revision 2. The revised Section 11 of NUMARC 93–01, Revision 2, was subsequently incorporated into Revision 3 of NUMARC 93–01 (Reference 5). However, Revision 3 has not yet been formally endorsed by the NRC. The changes in TSTF–423 are consistent with the rules, regulations and associated regulatory guidance, as noted above. 3.0 Technical Evaluation The changes proposed in TSTF–423 are consistent with the changes proposed and justified in Topical Report GE NEDC–32988–A, Revision 2, and approved by the associated NRC SE (Reference 6). The evaluation included in Reference 6, as appropriate and applicable to the changes of TSTF–423 (Reference 7), is reiterated here and differences from the SE are justified. In its application the licensee commits to TSTF–IG–05–02, Implementation Guidance for TSTF–423, Revision 0, ‘‘Technical Specifications End States, NEDC–32988–A,’’ (Reference 8), which addresses a variety of issues such as considerations and compensatory actions for risk-significant plant configurations. An overview of the generic evaluation and associated risk assessment is provided below, along with a summary of the associated TS changes justified by Reference 1. 3.1 Risk Assessment The objective of the BWROG topical report (Reference 1) risk assessment was to show that any risk increases associated with the proposed changes in TS end states are either negligible or negative (i.e., a net decrease in risk). The BWROG topical report documents a risk-informed analysis of the proposed TS change. Probabilistic Risk Assessment (PRA) results and insights are used, in combination with results of deterministic assessments, to E:\FR\FM\14DEN1.SGM 14DEN1 74040 Federal Register / Vol. 70, No. 239 / Wednesday, December 14, 2005 / Notices identify and propose changes in ‘‘end states’’ for all BWR plants. This is in accordance with guidance provided in RG 1.174 (Reference 9) and RG 1.177 (Reference 10). The three-tiered approach documented in RG 1.177, ‘‘An Approach for Plant-Specific, RiskInformed Decision Making: Technical Specifications,’’ was followed. The first tier of the three-tiered approach includes the assessment of the risk impact of the proposed change for comparison to acceptance guidelines consistent with the Commission’s Safety Goal Policy Statement, as documented in RG 1.174 entitled ‘‘An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on PlantSpecific Changes to the Licensing Basis.’’ In addition, the first tier aims at ensuring that there are no unacceptable temporary risk increases during the implementation of the proposed TS change, such as when equipment is taken out of service. The second tier addresses the need to preclude potentially high-risk configurations which could result if equipment is taken out of service concurrently with the implementation of the proposed TS change. The third tier addresses the application of 10 CFR 50.65(a)(4) of the Maintenance Rule for identifying risksignificant configurations resulting from maintenance related activities and taking appropriate compensatory measures to avoid such configurations. Unless invoked, such as by this or another TS application, 50.65(a)(4) is applicable to maintenance related activities and does not cover other operational activities beyond the effect they may have on existing maintenance related risk. BWROG’s risk assessment approach was found comprehensive and acceptable in the SE for the topical report. In addition, the analyses show that the three-tiered approach criteria for allowing TS changes are met as follows: • Risk Impact of the Proposed Change (Tier 1). The risk changes associated with the TS changes in TSTF–423, in terms of mean yearly increases in core damage frequency (CDF) and large early release frequency (LERF), are risk neutral or risk beneficial. In addition, there are no significant temporary risk increases, as defined by RG 1.177 criteria, associated with the implementation of the TS end state changes. • Avoidance of Risk-Significant Configurations (Tier 2). The performed risk analyses, which are based on single LCOs, shows that there are no high-risk configurations associated with the TS end state changes. The reliability of VerDate Aug<31>2005 15:29 Dec 13, 2005 Jkt 208001 redundant trains is normally covered by a single LCO. When multiple LCOs occur, which affect trains in several systems, the plant’s risk-informed configuration risk management program (CRMP), or the risk assessment and management program implemented in response to the Maintenance Rule 10 CFR 50.65(a)(4), shall ensure that highrisk configurations are avoided. As part of the implementation of TSTF–423, the licensee commits to follow Section 11 of NUMARC 93–01, Revision 3, and include guidance in appropriate plant procedures and/or administrative controls to preclude high-risk plant configurations when the plant is at the proposed end state. The staff finds that such guidance is adequate for preventing risk-significant plant configurations. • Configuration Risk Management (Tier 3). The licensee has a program in place to comply with 10 CFR 50.65 (a)(4) to assess and manage the risk from proposed maintenance activities. This program can support a licensee decision in selecting the appropriate actions to control risk for most cases in which a risk-informed TS is entered. The generic risk impact of the proposed end state mode change was evaluated subject to the following assumptions: 1. The entry into the proposed end state is initiated by the inoperability of a single train of equipment or a restriction on a plant operational parameter, unless otherwise stated in the applicable technical specification. 2. The primary purpose of entering the end state is to correct the initiating condition and return to power as soon as is practical. 3. When Mode 3 is entered as the repair end state, the time the reactor coolant pressure is above 500 psig will be minimized. If reactor coolant pressure is above 500 psig for more than 12 hours, the associated plant risk will be assessed and managed. These assumptions are consistent with typical entries into Mode 3 for short duration repairs, which is the intended use of the TS end state changes. The staff concludes that, in general, going to Mode 3 (hot shutdown) instead of going to Mode 4 (cold shutdown) to carry out equipment repairs that are of short duration, does not have any adverse effect on plant risk. 3.2 Assessment of TS Changes The changes proposed by the licensee and in TSTF–423 are consistent with the changes proposed in topical report GE NEDC–32988, Revision 2, and approved by the NRC SE of September PO 00000 Frm 00053 Fmt 4703 Sfmt 4703 27, 2002. [NOTE: Only those changes proposed in TSTF–423 are addressed in this SE. The SE and associated topical report address the entire fleet of BWR plants, and the plants adopting TSTF– 423 must confirm the applicability of the changes to their plant.] Following are the proposed changes, including a synopsis of the STS LCO, the change, and a brief conclusion of acceptability. 3.2.1 TS 4.5.1.2 and LCO 3.4.3 (BWR/ 4); TS 4.5.2.2 and LCO 3.4.4 (BWR/6), Safety/Relief Valves (SRVs) The function of the SRVs is to protect the plant against severe overpressurization events. These TS provide the operability requirements for the SRVs as described below. The TS change allows the plant to remain in Mode 3 until the repairs are completed. [Note: Plant Applicability, BWR4/6] LCO: The safety function of 11 SRVs must be operable (BWR/4 plants). The safety function of seven SRVs must be operable and the relief function of seven additional SRVs must be operable (BWR/6 plants). Condition requiring entry into end state: If the LCO cannot be met with one or two SRVs inoperable, the inoperable valves must be returned to operability within 14 days. If the SRVs cannot be returned to operable status within that time, the plant must be placed in Mode 3 within 12 hours and in Mode 4 within 36 hours. Proposed modification for end state required actions: If the LCO cannot be met with one or two SRVs inoperable, the inoperable valves must be returned to operability within 14 days. If the one or two inoperable SRVs cannot be returned to operable status within 14 days, the plant must be placed in Mode 3 within 12 hours. If three or more SRVs become inoperable, the plant must be placed in Mode 4 within 36 hours. Assessment: The BWROG topical report did a comparative PRA evaluation of the core damage risks of operation in the current end state and in the proposed Mode 3 end state. The evaluation indicates that the core damage risks are lower in Mode 3 than in Mode 4. Going to Mode 4 for one inoperable SRV would cause loss of the high-pressure steam-driven injection system (reactor core isolation cooling (RCIC)/high pressure coolant injection (HPCI)), and loss of the power conversion system (condenser/ feedwater), and require activating the residual heat removal (RHR) system. In addition, emergency operating procedures (EOPs) direct the operator to take control of the depressurization function if low pressure injection/spray E:\FR\FM\14DEN1.SGM 14DEN1 Federal Register / Vol. 70, No. 239 / Wednesday, December 14, 2005 / Notices systems are needed for reactor pressure vessel (RPV) water makeup and cooling. Based on the low probability of loss of the necessary overpressure protection function and the number of systems available in Mode 3, the staff concludes in the SE (reference 6) for the BWROG topical report that the risks of staying in Mode 3 are approximately the same as, and in some cases lower than, the risks of going to the Mode 4 end state. The change allows the inoperable SRV to be repaired in a plant operating mode with lower risks. After repairs are made, the plant can be brought to full-power operation with less potential for transients and errors. The plant is taken into cold shutdown only when three or more SRVs are inoperable. Since the time spent in Mode 3 to perform the repair is infrequent and limited, the proposed change is acceptable, particularly in light of defense-in-depth considerations. Finding: Based on the above assessment, the staff finds that the requested change to allow operation in Mode 3 with a minimum number of SRVs inoperable after plant risk has been assessed and managed, is acceptable. 3.2.2 TS 4.5.1.3 and LCO 3.5.1 (BWR/ 4); TS 4.5.2.3 and LCO 3.5.1 (BWR/6), Emergency Core Cooling Systems (ECCS) (Operating) The ECCS systems provide cooling water to the core in the event of a lossof-coolant accident (LOCA). This set of ECCS TS provide the operability requirements for the various ECCS subsystems as described below. This TS change would delete the secondary actions. The plant can remain in Mode 3 until the required repair actions are completed. The reactor is not depressurized. [Note: Plant Applicability, BWR4/6] LCO: Each ECCS injection/spray subsystem and the automatic depressurization system (ADS) function of seven BWR/4, or eight BWR/6, SRVs must be operable. Conditions requiring entry into end state: If the LCO cannot be met, the following actions must be taken for the listed conditions: a. If one low-pressure ECCS injection/ spray subsystem is inoperable, the subsystem must be restored to operable status in 7 days. b. If the inoperable ECCS injection/ core spray cannot be restored to operable status, the plant must be placed in Mode 3 within 12 hours and Mode 4 within 36 hours (BWR/4 plants only). VerDate Aug<31>2005 15:29 Dec 13, 2005 Jkt 208001 c. If two ECCS injection subsystems are inoperable or one ECCS injection subsystem and one ECCS spray system are inoperable, one ECCS injection/ spray subsystem must be restored to operable status within 72 hours. If this required action cannot be met, the plant must be placed in Mode 3 within 12 hours and in Mode 4 within 36 hours (BWR/6 plants only). d. If the HPCI/High Pressure Core Spray (HPCS) system is inoperable, the RCIC system must be verified to be operable by administrative means within 1 hour and the HPCI/HPCS system restored to operable status within 14 days. e. If one ADS valve is inoperable, it must be restored to operable status within 14 days. f. If one ADS valve is inoperable and one low-pressure ECCS injection/spray subsystem is inoperable, the ADS valve must be restored to operable status within 72 hours or the low-pressure ECCS injection/spray subsystem must be restored to operable status within 72 hours. g. If two or more ADS valves become inoperable, or the required actions described in items e and/or f cannot be met, the plant must be placed in Mode 3 within 12 hours and the reactor steam dome pressure reduced to less than 150 psig within 36 hours. Proposed modification for end state required actions: a. No change b. If the ECCS injection or spray system is inoperable, the plant must be restored to operable status within 12 hours. The plant is not taken into Mode 4 (cold shutdown). c. If two ECCS injection subsystems are inoperable or one ECCS injection subsystem and one ECCS spray system are inoperable, one ECCS injection/ spray subsystem must be restored to operable status within 72 hours. If this required action cannot be met, the plant must be placed in Mode 3 within 12 hours. The plant is not taken into Mode 4 (BWR/6 plants only). d. No change e. No change f. No change g. If two or more ADS valves become inoperable or the required actions described in item e and/or f cannot be met, the plant must be placed in Mode 3 within 12 hours. The reactor is not depressurized and not taken to Mode 4. Assessment: The BWROG topical report did a comparative PRA evaluation of the core damage risks of operation in the current end state and the proposed Mode 3 end state. The evaluation indicates that the core damage risks are lower in Mode 3 than PO 00000 Frm 00054 Fmt 4703 Sfmt 4703 74041 in the current end state Mode 4. Going to Mode 4 for one ECCS subsystem or one ADS valve would cause loss of the high-pressure steam-driven injection system (RCIC/HPCI), and loss of the power conversion system (condenser/ feedwater), and require activating the RHR system. In addition, Plant Emergency Operating Procedures (EOPs) direct the operator to take control of the depressurization function if lowpressure injection/spray systems are needed for RPV water makeup and cooling. Based on the low probability of loss of the reactor coolant inventory and the number of systems available in Mode 3, the staff concludes in the SE to the BWR topical report that the risks of staying in Mode 3 are approximately the same as, and in some cases lower than, the risks of going to the Mode 4 end state. Finding: Based on the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. 3.2.3 TS 4.5.1.4 and LCO 3.5.3 (BWR/ 4 only), Reactor Core Isolation Cooling (RCIC) System The function of the RCIC system is to provide reactor coolant makeup during loss of feedwater and other transient events. This TS provides the operability requirements for the RCIC system as described below. The TS change allows the plant to remain in Mode 3 until the repairs are completed. [Note: Plant Applicability, BWR/4] LCO: The RCIC system must be operable during Modes 1, 2 and 3 when the reactor steam dome pressure is greater than 150 psig. Condition requiring entry into end state: If the LCO cannot be met, the following actions must be taken: (a) verify by administrative means within 1 hour that the HPCI system is operable, (b) restore the RCIC system to operable status within 14 days. If either or both actions cannot be completed within the allotted time, the plant must be placed in Mode 3 within 12 hours and the reactor steam dome pressure reduced to less than 150 psig within 36 hours. Proposed modification for end state required actions: This TS change keeps the plant in Mode 3 (hot shutdown) until the required repairs are completed. The reactor steam dome pressure is not reduced to less than 150 psig. Assessment: This change would allow the inoperable RCIC system to be repaired in a plant operating mode with lower risk and without challenging the normal shutdown systems. The BWROG E:\FR\FM\14DEN1.SGM 14DEN1 74042 Federal Register / Vol. 70, No. 239 / Wednesday, December 14, 2005 / Notices topical report did a comparative PRA evaluation of the core damage risks of operation in the current end state and in the proposed Mode 3 end state. The evaluation indicates that the core damage risks are lower in Mode 3 than in Mode 4. Going to Mode 3 with reactor steam dome pressure less than 150 psig for inoperability of RCIC would also cause loss of the high-pressure steamdriven injection system HPCI and loss of the power conversion system (condenser/ feedwater), and would require activating the RHR system. In addition, Plant EOPs direct the operator to take control of the depressurization function if low pressure injection/spray systems are needed for RPV water makeup and cooling. Based on the low probability of loss of the necessary overpressure protection function and the number of systems available in Mode 3, the staff concludes in the SE to the BWR topical report that the risks of staying in Mode 3 are approximately the same as, and in some cases lower than, the risks of going to the Mode 4 end state. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. 3.2.4 TS 4.5.1.6 and LCO 3.6.1.6 (BWR/4); TS 5.5.2.5 and LCO 3.6.1.6 (BWR/6), Low-Low Set Logic (LLS) Valves The function of LLS logic is to prevent excessive short-duration SRV cycling during an overpressure event. This TS provides operability requirements for the four LLS SRVs as described below. The TS change allows the plant to remain in Mode 3 until the repairs are completed. [Note: Plant Applicability, BWR 4/6] Conditions requiring entry into end state: If one LLS valve is inoperable, it must be returned to operability within 14 days. If the LLS valve cannot be returned to operable status within the allotted time, the plant must be placed in Mode 3 within 12 hours and in Mode 4 within 36 hours. Proposed modification for end state required actions: The TS change would keep the plant in Mode 3 until the required repair actions are completed. The plant would not be taken into Mode 4 (cold shutdown). Assessment: The BWROG topical report did a comparative PRA evaluation of the core damage risks of operation in the current end state and the proposed Mode 3 end state. The evaluation indicates that the core VerDate Aug<31>2005 15:29 Dec 13, 2005 Jkt 208001 damage risks are lower in Mode 3 than in Mode 4, the current end state. Going to Mode 4 for one LLS inoperable SRV would cause loss of the high-pressure steam-driven injection system (RCIC/ HPCI), and loss of the power conversion system (condenser/feedwater), and would require activating the RHR system. With one LLS valve inoperable, the remaining valves are adequate to perform the required function. EOPs direct the operator to take control of the depressurization function if low pressure injection/spray systems are needed for RPV water makeup and cooling. Based on the low probability of loss of the necessary overpressure protection function during the infrequent and limited time in Mode 3 and the number of systems available in Mode 3, the staff concludes in the SE to the BWR topical report that the risks of staying in Mode 3 are approximately the same as and in some cases lower than the risks of going to the Mode 4 end state. The proposed change allows repairs of the inoperable SRV to be performed in a plant operating mode with lower risks. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. 3.2.5 TS 4.5.1.1, TS 4.5.2.1 and LCO 3.3.8.2, Reactor Protection System (RPS) Electric Power Monitoring RPS Electric Power Monitoring System is provided to isolate the RPS bus from the motor generator (MG) set or an alternate power supply in the event of over voltage, under voltage, or under frequency. This system protects the load connected to the RPS bus against unacceptable voltage and frequency conditions and forms an important part of the primary success path of the essential safety circuits. Some of the essential equipment powered from the RPS buses includes the RPS logic, scram solenoids, and various valve isolation logic. The TS change allows the plant to remain in Mode 3 until the repairs are completed. [Note: Plant Applicability, BWR 4/6] LCO: For Modes 1, 2, 3 and Modes 4 and 5 (with any control rod withdrawn from a core cell containing one or more fuel assemblies), two RPS electric power monitoring assemblies shall be operable for each in-service RPS motor generator set or alternate power supply. Condition Requiring Entry into End State: If the LCO cannot be met, the associated in-service power supply(s) must be removed from service within 72 PO 00000 Frm 00055 Fmt 4703 Sfmt 4703 hours for one Electric Power Assembly (EPA) inoperable or within one hour for both EPAs inoperable. In Modes 1, 2, and 3, if the in-service power supply(s) cannot be removed from service within the allotted time, the plant must be placed in Mode 3 within 12 hours and Mode 4 within 36 hours. Proposed Modification: The proposed change is to keep the plant in Mode 3 until the repair actions are completed. Delete required action in C.2 which required the plant to be in Mode 4. Assessment: To reach Mode 3 per the TS, there must be a functioning power supply with degraded protective circuitry in operation. However, the over voltage, under voltage, or under frequency condition must exist for an extended time period to cause damage. There is a low probability of this occurring in the short period of time that the plant would remain in Mode 3 without this protection. The specific failure condition of interest is not risk significant for BWR PRAs. If the required restoration actions cannot be completed within the specified time, going into Mode 4 would cause loss of the high-pressure steamdriven injection system (RCIC/HPCI) and loss of the power conversion system (condenser/feedwater), and would require activating the RHR system. In addition, EOPs direct the operator to take control of the depressurization function if low pressure injection/spray systems are needed for RPV water makeup and cooling. Based on the low probability of loss of the RPS power monitoring system during the infrequent and limited time in Mode 3 and the number of systems available in Mode 3, the staff concludes in the SE to the BWR topical report that the risks of staying in Mode 3 are approximately the same as and in some cases lower than the risks of going to the Mode 4 end state. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. 3.2.6 TS 4.5.1.19 and LCO 3.8.1(BWR/ 4); TS 4.5.2.17 and LCO 3.8.1(BWR/6), AC Sources (Operating) The purpose of the AC electrical system is to provide during all situations the power required to put and maintain the plant in a safe condition and prevent the release of radioactivity to the environment. The Class 1E electrical power distribution system AC sources consist of the offsite power source (preferred power sources, normal and alternate(s)), and the onsite standby power sources E:\FR\FM\14DEN1.SGM 14DEN1 Federal Register / Vol. 70, No. 239 / Wednesday, December 14, 2005 / Notices (e.g., emergency diesel generators (EDGs)). In addition, many sites provide a crosstie capability between units. As required by General Design Criterion (GDC) 17 of 10 CFR Part 50, Appendix A, the design of the AC electrical system provides independence and redundancy. The onsite Class 1E AC distribution system is divided into redundant divisions so that the loss of any one division does not prevent the minimum safety functions from being performed. Each division has connections to two preferred offsite power sources and a single EDG or other Class 1E Standby AC power source. Offsite power is supplied to the unit switchyard(s) from the transmission network by two transmission lines. From the switchyard(s), two electrically and physically separated circuits provide AC power through a stepdown transformer(s) to the 4.16-kV emergency buses. In the event of a loss of offsite power, the emergency electrical loads are automatically connected to the EDGs in sufficient time to provide for a safe reactor shutdown and to mitigate the consequence of a design basis accident (DBA) such as a LOCA. [Note: Plant Applicability, BWR 4/6] LCO: The following AC electrical power sources shall be operable in Modes 1, 2, and 3: a. Two qualified circuits between the offsite transmission network and the onsite Class1E AC Electric Power Distribution System, b. Three EDGs, c. Automatic Load Sequencers. Condition requiring entry into end state: Plant operators must bring the plant to Mode 4 within 36 hours following the sustained inoperability of one required Automatic Load Sequencer; either or both required offsite circuits; either one, two or three required EDGs; or one required offsite circuit and one, two or three required EDGs. Proposed modification for end state require actions: Delete required action G.2 to go to Mode 4 (cold shutdown). The plant will remain in Mode 3 (hot shutdown). Assessment: Entry into any of the conditions for the AC power sources implies that the AC power sources have been degraded and the single failure protection for the safe shutdown equipment may be ineffective. Consequently, as specified in TS 3.8.1 at present, the plant operators must bring the plant to Mode 4 when the required action is not completed by the specified time for the associated action. VerDate Aug<31>2005 15:29 Dec 13, 2005 Jkt 208001 The BWROG topical report did a comparative PRA evaluation of the core damage risks of operation in the current end state and in the proposed Mode 3 end state. Events initiated by the loss of offsite power are dominant contributors to core damage frequency in most BWR PRAs, and the steam-driven core cooling systems, RCIC and HPCI, play a major role in mitigating these events. The evaluation indicates that the core damage risks are lower in Mode 3 than in Mode 4 for one inoperable AC power source. Going to Mode 4 for one inoperable AC power source would cause loss of the high-pressure steamdriven injection system (RCIC/HPCI), and loss of the power conversion system (condenser/feedwater), and require activating the RHR system. In addition, EOPs direct the operator to take control of the depressurization function if low pressure injection/spray systems are needed for RPV water makeup and cooling. Based on the low probability of loss of the AC power and the number of steam-driven systems available in Mode 3, the staff concludes in the SE to the BWR topical report that the risks of staying in Mode 3 are lower than going to the Mode 4 end state. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. 3.2.7 TS 4.5.1.20 and LCO 3.8.4 (BWR/ 4); TS 4.5.2.18 and LCO 3.8.4 DC Sources (Operating) The purpose of the DC power system is to provide a reliable source of DC power for both normal and abnormal conditions. It must supply power in an emergency for an adequate length of time until normal supplies can be restored. The DC electrical system: a. Provides the AC emergency power system with control power, b. Provides motive and control power to selected safety related equipment, and c. Provides power to preferred AC vital buses (via inverters). [Note: Plant Applicability, BWR 4/6] LCO: For Modes 1, 2 and 3, the following DC sources are required to be operable: BWR/4: The (Division 1 and Division 2 station service, and DG 1B, 2A, and 2C) DC electrical power systems shall be operable. BWR/6: The (Divisions 1, 2, and 3) DC electrical power subsystems shall be operable. PO 00000 Frm 00056 Fmt 4703 Sfmt 4703 74043 Condition requiring entry into end state: The plant operators must bring the plant to Mode 3 within 12 hours and Mode 4 within 36 hours following the sustained inoperability of one DC electrical power subsystem for a period of 2 hours. Proposed modification for end state required actions: The proposed TS change is to remove the requirement to place the plant in Mode 4, Required Actions in D.2 (BWR/4) and E.2 (BWR/ 6) are deleted. Assessment: If one of the DC electrical power subsystems is inoperable, the remaining DC electrical power subsystems have the capacity to support a safe shutdown and to mitigate an accident condition. The BWROG topical report did a comparative PRA evaluation of the core damage risks of operation in the current end state and in the proposed Mode 3 end state, with one DC system inoperable. Events initiated by the loss of offsite power are dominant contributors to core damage frequency in most BWR PRAs, and the steam-driven core cooling systems, RCIC and HPCI, play a major role in mitigating these events. The evaluation indicates that the core damage risks are lower in Mode 3 than in Mode 4. Going to Mode 4 for one inoperable DC power source would cause loss of the highpressure steam-driven injection system (RCIC/HPCI), and loss of the power conversion system (condenser/ feedwater), and require activating the RHR system. In addition, EOPs direct the operator to take control of the depressurization function if low pressure injection/spray systems are needed for RPV water makeup and cooling. Based on the low probability of loss of the DC power and the number of systems available in Mode 3, the staff concludes in the SE to the BWR topical report that the risks of staying in Mode 3 are approximately the same as and in some cases lower than the risks of going to the Mode 4 end state. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. 3.2.8 TS 4.5.1.21 and LCO 3.8.7 (BWR/ 4); TS 4.5.2.19 and 3.8.7 (BWR/6), Inverters (Operating) In Modes 1, 2, and 3, the inverters provide the preferred source of power for the 120-VAC vital buses which power the reactor protection system (RPS) and the Emergency Core Cooling Systems (ECCS) initiation. The inverter can be powered from an internal AC E:\FR\FM\14DEN1.SGM 14DEN1 74044 Federal Register / Vol. 70, No. 239 / Wednesday, December 14, 2005 / Notices source/rectifier or from the station battery. [Note: Plant Applicability, BWR 4/6] LCO: For Modes 1, 2, and 3 the following Inverters shall be operable: BWR/4: The (Division 1 and Division 2) shall be operable. BWR/6: The (Divisions 1, 2, and 3) shall be operable. Condition requiring entry into end state: The plant operators must bring the plant to Mode 3 within 12 hours and Mode 4 within 36 hours following the sustained inoperability of the required inverter for a period of 24 hours. Proposed modification for end state required actions: The proposed TS change is to remove the requirement to place the plant in Mode 4. Required Actions in B.2 (BWR/4) and C.2 (BWR/ 6) are deleted. Assessment: If one of the Inverters is inoperable, the remaining Inverters have the capacity to support a safe shutdown and to mitigate an accident condition. The BWROG topical report did a comparative PRA evaluation of the core damage risks of operation in the current end state and in the proposed Mode 3 end state, with an inoperable Inverter. Events initiated by the loss of offsite power are dominant contributors to core damage frequency in most BWR PRAs, and the steam-driven core cooling systems, RCIC and HPCI, play a major role in mitigating these events. The evaluation indicates that the core damage risks are lower in Mode 3 than in Mode 4. Going to Mode 4 for one inoperable Inverter power source would cause loss of the high-pressure steamdriven injection system (RCIC/HPCI), and loss of the power conversion system (condenser/feedwater), and require activating the RHR system. In addition, EOPs direct the operator to take control of the depressurization function if low pressure injection/spray systems are needed for RPV water makeup and cooling. Based on the low probability of loss of the Inverters during the infrequent and limited time in Mode 3 and the number of systems available in Mode 3, the staff concludes in the SE to the BWR topical report that the risks of staying in Mode 3 are approximately the same as and in some cases lower than the risks of going to the Mode 4 end state. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. VerDate Aug<31>2005 15:29 Dec 13, 2005 Jkt 208001 3.2.9 TS 4.5.1.22 and LCO 3.8.9 (BWR/ 4); TS 4.5.2.20 and LCO 3.8.9 (BWR/6), Distribution Systems (Operating) The onsite Class 1E AC and DC electrical power distribution system is divided into redundant and independent AC, DC, and AC vital bus electrical power distribution systems. The primary AC electrical power distribution subsystem for each division consists of a 4.16-kV Engineered Safety Feature (ESF) bus having an offsite source of power as well as a dedicated onsite EDG source. The secondary plant distribution subsystems include 600VAC emergency buses and associated load centers, motor control centers, distribution panels and transformers. The 120-VAC vital buses are arranged in four load groups and normally powered from DC via the inverters. There are two independent 125/250-VDC station service electrical power distribution systems and three independent 125VDC DG electrical power distribution subsystems that support the necessary power for ESF functions. Each subsystem consists of a 125-VDC and 250-VDC bus and associated distribution panels. [Note: Plant Applicability, BWR 4/6] LCO: For Modes 1, 2, and 3, the following electrical power distribution subsystems shall be operable: BWR/4: The Division 1 and Division 2 AC, DC, and AC vital buses shall be operable. BWR/6: The Divisions 1, 2, and 3 AC, DC, and AC vital buses shall be operable. Condition requiring entry into end state: The plant operators must bring the plant to Mode 3 within 12 hours and Mode 4 within 36 hours following the sustained inoperability of one AC or one DC or one AC vital bus electrical power subsystem for a period of 8 hours, 2 hours and 2 hours, respectively (with a maximum 16 hour Completion Time limit from initial discovery of failure to meet the LCO, to preclude being in the LCO indefinitely). Proposed modification for end state required actions: The proposed TS change is to remove the requirement to place the plant in Mode 4, Required Action in D.2 (BWR/4) and D.2 (BWR/ 6) are deleted. Assessment: If one of the AC/DC/AC vital subsystems is inoperable, the remaining AC/DC/AC vital subsystems have the capacity to support a safe shutdown and to mitigate an accident condition. The BWROG topical report did a comparative PRA evaluation of the core damage risks of operation in the current end state and in the proposed Mode 3 end state, with one of the AC/ PO 00000 Frm 00057 Fmt 4703 Sfmt 4703 DC/AC vital subsystems inoperable. Events initiated by the loss of offsite power are dominant contributors to core damage frequency in most BWR PRAs, and the steam-driven core cooling systems, RCIC and HPCI, play a major role in mitigating these events. The evaluation indicates that the core damage risks are lower in Mode 3 than in Mode 4. Going to Mode 4 for one inoperable AC/DC/AC vital subsystem would cause loss of the high-pressure steam-driven injection system (RCIC/ HPCI), and loss of the power conversion system (condenser/feedwater), and require activating the RHR system. In addition, EOPs direct the operator to take control of the depressurization function if low pressure injection/spray systems are needed for RPV water makeup and cooling. Based on the low probability of loss of the AC/DC/AC vital electrical subsystems during the infrequent and limited time in Mode 3 and the number of systems available in Mode 3, the staff concludes in the SE to the BWR topical report that the risks of staying in Mode 3 are approximately the same as and in some cases lower than the risks of going to the Mode 4 end state. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. 3.2.10 TS 4.5.1.5 and LCO 3.6.1.1, Primary Containment The function of the primary containment is to isolate and contain fission products released from the Reactor Primary System following a design basis LOCA and to confine the postulated release of radioactivity. The primary containment consists of a steellined, reinforced concrete vessel, which surrounds the Reactor Primary System and provides an essentially leak-tight barrier against an uncontrolled release of radioactivity to the environment. Additionally, this structure provides shielding from the fission products that may be present in the primary containment atmosphere following accident conditions. [Note: Plant Applicability, BWR 4/6] LCO: The primary containment shall be operable. Condition Requiring Entry into End State: If the LCO cannot be met, the primary containment must be returned to operability within one hour (Required Action A.1). If the primary containment cannot be returned to operable status within the allotted time, the plant must be placed in Mode 3 within 12 hours E:\FR\FM\14DEN1.SGM 14DEN1 Federal Register / Vol. 70, No. 239 / Wednesday, December 14, 2005 / Notices (Required Action B.1) and in Mode 4 within 36 hours (Required Action B.2). Proposed Modification for End State Required Actions: Delete Required Action B.2. Assessment: The primary containment is one of the three primary boundaries to the release of radioactivity. (The other two are the fuel cladding and the Reactor Primary System pressure boundary.) Compliance with this LCO ensures that a primary containment configuration exists, including equipment hatches and penetrations, that is structurally sound and will limit leakage to those leakage rates assumed in the safety analyses. This LCO entry condition does not include leakage through an unisolated release path. The BWROG topical report has determined that previous generic PRA work related to Appendix J requirements has shown that containment leakage is not risk significant. Should a fission product release from the primary containment occur, the secondary containment and related functions would remain operable to contain the release, and the standby gas treatment system would remain available to filter fission products from being released to the environment. By remaining in Mode 3, HPCI, RCIC, and the power conversion system (condensate/feedwater) remain available for water makeup and decay heat removal. Additionally, the EOPs direct the operators to take control of the depressurization function if low pressure injection/spray are needed for reactor coolant makeup and cooling. Therefore, defense-in-depth is maintained with respect to water makeup and decay heat removal by remaining in Mode 3. Finding: The requested change is acceptable. Note that the staff’s approval relies upon the secondary containment and the standby gas treatment system for maintaining defense-in-depth while in this reduced end state. 3.2.11 TS 4.5.1.7 and LCO 3.6.1.7, Reactor Building-to-Suppression Chamber Vacuum Breakers (BWR/4 only) The reactor building-to-suppression chamber vacuum breakers relieve vacuum when the primary containment depressurizes below the pressure of the reactor building, thereby serving to preserve the integrity of the primary containment. [Note: Plant Applicability, BWR/4] LCO: Each reactor building-tosuppression chamber vacuum breaker shall be operable. VerDate Aug<31>2005 15:29 Dec 13, 2005 Jkt 208001 Condition Requiring Entry into End State: If one line has one or more reactor building-to-suppression chamber vacuum breakers inoperable for opening, the breaker(s) must be returned to operability within 72 hours (Required Action C.1). If the vacuum breaker(s) cannot be returned to operability within the allotted time, the plant must be placed in Mode 3 within 12 hours (Required Action E.1) and in Mode 4 within 36 hours (Required Action E.2). Proposed Modification for End State Required Actions: Modify the Required Actions so that if vacuum breaker(s) cannot be returned to operable status within the required Completion Times, the plant is placed in hot shutdown. That is, modify Condition E to relate only to Condition C, delete Required Action E.2, and add Condition F, with Required Actions F.1 and F.2, shutting down the plant to Mode 3 and then Mode 4 respectively, to address an inability to comply with the required actions related to the other Conditions (i.e., Conditions A, B, and D). Assessment: The BWROG topical report has determined that the specific failure condition of interest is not risk significant in BWR PRAs. The reduced end state would only be applicable to the situation where the vacuum breaker(s) in one line are inoperable for opening, with the remaining operable vacuum breakers capable of providing the necessary vacuum relief function. The existing end state remains unchanged, as established by new Condition F, for conditions involving more than one inoperable line or vacuum breaker since they are needed in Modes 1, 2, and 3. In Mode 3, for other accident considerations, HPCI, RCIC, and the power conversion system (condensate/feedwater) remain available for water makeup and decay heat removal. Additionally, the EOPs direct the operators to take control of the depressurization function if low pressure injection/spray are needed for reactor coolant makeup and cooling. Therefore, defense-in-depth is maintained with respect to water makeup and decay heat removal by remaining in Mode 3. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. 3.2.12 TS 4.5.1.8 and LCO 3.6.1.8, Suppression Chamber-to-Drywell Vacuum Breakers (BWR/4 only) The function of the suppression chamber-to-drywell vacuum breakers is to relieve vacuum in the drywell, PO 00000 Frm 00058 Fmt 4703 Sfmt 4703 74045 thereby preventing an excessive negative differential pressure across the wetwell/drywell boundary. [Note: Plant Applicability, BWR/4] LCO: Nine suppression chamber-todrywell vacuum breakers shall be operable for opening. Condition Requiring Entry into End State: If one suppression chamber-todrywell vacuum breaker is inoperable for opening, the breaker must be returned to operability within 72 hours (Required Action A.1). If the vacuum breaker cannot be returned to operability within the allotted time, the plant must be placed in Mode 3 within 12 hours (Required Action C.1) and in Mode 4 within 36 hours (Required Action C.2). Proposed Modification for End State Required Actions: Modify the Required Actions so that if vacuum breaker(s) cannot be returned to operable status within the required Completion Times, the plant is placed in hot shutdown. That is, modify Condition C to relate only to Condition A, and delete Required Action C.2, and add Condition D, with Required Actions D.1 and D.2, shutting down the plant to Mode 3 and then Mode 4 respectively, to address an inability to comply with the required actions related to Condition B, to close the vacuum breaker. Assessment: The BWROG topical report has determined that the specific failure of interest is not risk significant in BWR PRAs. The reduced end state would only be applicable to the situation where one suppression chamber-to-drywell vacuum breaker is inoperable for opening, with the remaining operable vacuum breakers capable of providing the necessary vacuum relief function, since they are required in Modes 1, 2, and 3. By remaining in Mode 3, HPCI, RCIC, and the power conversion system (condensate/feedwater) remain available for water makeup and decay heat removal. Additionally, the EOPs direct the operators to take control of the depressurization function if low pressure injection/spray are needed for RCS makeup and cooling. Therefore, defense-in-depth is maintained with respect to water makeup and decay heat removal by remaining in Mode 3. The existing end state remains unchanged for conditions involving any suppression chamber-to-drywell vacuum breakers that are stuck open, as established by new Condition D. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of E:\FR\FM\14DEN1.SGM 14DEN1 74046 Federal Register / Vol. 70, No. 239 / Wednesday, December 14, 2005 / Notices defense-in-depth considerations, the proposed change is acceptable. 3.2.13 TS 4.5.1.9, TS 4.5.2.8, and LCO 3.6.1.9, Main Steam Isolation Valve (MSIV) Leakage Control System (LCS) The MSIV LCS supplements the isolation function of the MSIVs by processing the fission products that could leak through the closed MSIVs after core damage, assuming leakage rate limits which are based on a large LOCA. [Note: Plant Applicability, BWR 4/6] LCO: Two MSIV LCS subsystems shall be operable. Condition Requiring Entry Into End State: If one MSIV LCS subsystem is inoperable, it must be restored to operable status within 30 days (Required Action A.1). If both MSIV LCS subsystems are inoperable, one of the MSIV LCS subsystems must be restored to operable status within seven days (Required Action B.1). If the MSIV LCS subsystems cannot be restored to operable status within the allotted time, the plant must be placed in Mode 3 within 12 hours (Required Action C.1) and in Mode 4 within 36 hours (Required Action C.2). Proposed Modification for End State Required Actions: Delete Required Action C.2. Assessment: The BWROG topical report has determined that this system is not significant in BWR PRAs and, based on a BWROG program, many plants have eliminated the system altogether. The unavailability of one or both MSIV LCS subsystems has no impact on CDF or LERF, irrespective of the mode of operation at the time of the accident. Furthermore, the challenge frequency of the MSIV LCS system (i.e., the frequency with which the system is expected to be challenged to mitigate offsite radiation releases resulting from MSIV leaks above TS limits) is less than 1.0E–6/yr. Consequently, the conditional probability that this system will be challenged during the repair time interval while the plant is at either the current or the proposed end state (i.e., Mode 4 or Mode 3, respectively) is less than 1.0E–8. This probability is considerably smaller than probabilities considered ‘‘negligible’’ in Regulatory Guide 1.177 for much higher consequence risks, such as large early release. Section 6 of reference 6 summarizes the staff’s risk argument for approval of TSs 4.5.1.9, 4.5.2.8, and LCO 3.6.1.9, ‘‘Main Steam Isolation Valve (MSIV) Leakage Control System (LCS).’’ The argument for staying in Mode 3 instead of going to Mode 4 to repair the MSIV LCS system (one or both trains) is also VerDate Aug<31>2005 15:29 Dec 13, 2005 Jkt 208001 supported by defense-in-depth considerations. Section 6.2 makes a comparison between the current (Mode 3) and the proposed (Mode 4) end state, with respect to the means available to perform critical functions (i.e., functions contributing to the defense-in-depth philosophy) whose success is needed to prevent core damage and containment failure and mitigate radiation releases. The risk and defense-in-depth arguments, used according to the ‘‘integrated decision-making’’ process of Regulatory Guides 1.174 and 1.177, support the conclusion that the plant in Mode 3 is as safe as Mode 4 (if not safer) for repairing an inoperable MSIV LCS system. Personnel safety must be considered separately. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. 3.2.14 TS 4.5.1.11 and LCO 3.6.2.4, Residual Heat Removal (RHR) Suppression Pool Spray(BWR/4 only) Following a DBA, the RHR suppression pool spray system removes heat from the suppression chamber airspace. A minimum of one RHR suppression pool spray subsystem is required to mitigate potential bypass leakage paths from drywell and maintain the primary containment peak pressure below the design limits. [Note: Plant Applicability, BWR/4] LCO: Two RHR suppression pool spray subsystems shall be operable. Condition Requiring Entry Into End State: If one RHR suppression pool spray subsystem is inoperable (Condition A), it must be restored to operable status within seven days (Required Action A.1). If both RHR suppression pool spray subsystems are inoperable (Condition B), one of them must be restored to operable status within eight hours (Required Action B.1). If the RHR suppression pool spray subsystem cannot be restored to operable status within the allotted time, the plant must be placed in Mode 3 within 12 hours (Required Action C.1), and in Mode 4 within 36 hours (Required Action C.2). Proposed Modification for End State Required Actions: Delete Required Action C.2. Assessment: The main function of the RHR suppression spray system is to remove heat from the suppression chamber so that the pressure and temperature inside primary containment remain within analyzed design limits. The RHR suppression spray system was PO 00000 Frm 00059 Fmt 4703 Sfmt 4703 designed to mitigate potential effects of a postulated DBA, that is, a large LOCA which is assumed to occur concurrently with the most limiting single failure and conservative inputs, such as for initial suppression pool water volume and temperature. Under the conditions assumed in the DBA, steam blown down from the break could bypass the suppression pool and end up in the suppression chamber air space and the RHR suppression spray system could be needed to condense such steam so that the pressure and temperature inside primary containment remain within analyzed design basis limits. However, the frequency of a DBA is very small and the containment has considerable margin to failure above the design limits. For these reasons, the unavailability of one or both RHR suppression spray subsystems has no significant impact on CDF or LERF, even for accidents initiated during operation at power. Therefore, it is very unlikely that the RHR suppression spray system will be challenged to mitigate an accident occurring during power operation. This probability becomes extremely unlikely for accidents that would occur during a small fraction of the year (less than three days) during which the plant would be in Mode 3 (associated with lower initial energy level and reduced decay heat load as compared to power operation) to repair the failed RHR suppression spray system. Section 6 of reference 6 summarizes the staff’s risk argument for approval of TS 4.5.1.11 and LCO 3.6.2.4, ‘‘Residual Heat Removal (RHR) Suppression Pool Spray.’’ The argument for staying in Mode 3 instead of going to Mode 4 to repair the RHR Suppression Pool Spray system (one or both trains) is also supported by defense-in-depth considerations. Section 6.2 makes a comparison between the current (Mode 3) and the proposed (Mode 4) end state, with respect to the means available to perform critical functions (i.e., functions contributing to the defense-in-depth philosophy) whose success is needed to prevent core damage and containment failure and mitigate radiation releases, and precluding the need for RHR suppression spray subsystems. In addition, the probability of a DBA (large break) is much smaller during shutdown as compared to power operation. A DBA in Mode 3 would be considerably less severe than a DBA occurring during power operation since Mode 3 is associated with lower initial energy level and reduced decay heat load. Under these extremely unlikely conditions, an alternate method that can be used to remove heat from the primary E:\FR\FM\14DEN1.SGM 14DEN1 Federal Register / Vol. 70, No. 239 / Wednesday, December 14, 2005 / Notices containment (in order to keep the pressure and temperature within the analyzed design basis limits) is containment venting. For more realistic accidents that could occur in Mode 3, several alternate means are available to remove heat from the primary containment, such as the RHR system in the suppression pool cooling mode and the containment spray mode. The risk and defense-in-depth arguments, used according to the ‘‘integrated decision-making’’ process of Regulatory Guides 1.174 and 1.177, support the conclusion that Mode 3 is as safe as Mode 4 (if not safer) for repairing an inoperable RHR suppression spray system. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. still be operable, including the standby gas treatment system, thereby minimizing the likelihood of an unacceptable release. By remaining in Mode 3, HPCI, RCIC, and the power conversion system (condensate/ feedwater) remain available for water makeup and decay heat removal. Additionally, the EOPs direct the operators to take control of the depressurization function if low pressure injection/spray are needed for RCS makeup and cooling. Therefore, defense-in-depth is improved with respect to water makeup and decay heat removal by remaining in Mode 3. Finding: The requested change is acceptable. Note that the staff’s approval relies upon the primary containment, and all other primary and secondary containment-related functions, to still be operable, including the standby gas treatment system, for maintaining defense-in-depth while in this end state. 3.2.15 TS 4.5.1.12, TS 4.5.2.10, and LCO 3.6.4.1, Secondary Containment Following a DBA, the function of the secondary containment is to contain, dilute, and stop radioactivity (mostly fission products) that may leak from primary containment. Its leak tightness is required to ensure that the release of radioactivity from the primary containment is restricted to those leakage paths and associated leakage rates assumed in the accident analysis and that fission products entrapped within the secondary containment structure will be treated by the standby gas treatment system prior to discharge to the environment. 3.2.16 TS 4.5.1.13, TS 4.5.2.11, and LCO 3.6.4.3, Standby Gas Treatment (SGT) System The function of the SGT system is to ensure that radioactive materials that leak from the primary containment into the secondary containment following a DBA are filtered and adsorbed prior to exhausting to the environment. Applicability: BWR4/6 LCO: Two SGT subsystems shall be operable. Condition Requiring Entry Into End State: If one SGT subsystem is inoperable, it must be restored to operable status within seven days (Required Action A.1). If the SGT subsystem cannot be restored to operable status within the allotted time, the plant must be placed in Mode 3 within 12 hours (Required Action B.1) and in Mode 4 within 36 hours (Required Action B.2). In addition, if two SGT subsystems are inoperable in Mode 1, 2, or 3, LCO 3.0.3 must be entered immediately (Required Action D.1). Proposed Modification for End State Required Actions: Delete Required Action B.2. Change Required Action D.1 to ‘‘Be in Mode 3’’ with a Completion Time of ‘‘12 hours.’’ Assessment: The unavailability of one or both SGT subsystems has no impact on CDF or LERF, irrespective of the mode of operation at the time of the accident. Furthermore, the challenge frequency of the SGT system (i.e., the frequency with which the system is expected to be challenged to mitigate offsite radiation releases resulting from materials that leak from the primary to the secondary containment above TS limits) is less than 1.0E–6/yr. [Note: Plant Applicability, BWR 4/6] LCO: The secondary containment shall be operable. Condition Requiring Entry Into End State: If the secondary containment is inoperable, it must be restored to operable status within four hours (Required Action A.1). If it cannot be restored to operable status within the allotted time, the plant must be placed in Mode 3 within 12 hours (Required Action B.1), and in Mode 4 within 36 hours (Required Action B.2). Proposed Modification for End State Required Actions: Delete Required Action B.2. Assessment: This LCO entry condition does not include gross leakage through an unisolable release path. The BWROG topical report has determined that previous generic PRA work related to Appendix J requirements has shown that containment leakage is not risk significant. The primary containment, and all other primary and secondary containment-related functions would VerDate Aug<31>2005 15:29 Dec 13, 2005 Jkt 208001 PO 00000 Frm 00060 Fmt 4703 Sfmt 4703 74047 Consequently, the conditional probability that this system will be challenged during the repair time interval while the plant is at either the current or the proposed end state (i.e., Mode 4 or Mode 3, respectively) is less than 1.0E–8. This probability is considerably smaller than probabilities considered ‘‘negligible’’ in Regulatory Guide 1.177 for much higher consequence risks, such as large early release. Section 6 of reference 6 summarizes the staff’s risk argument for approval of TSs 4.5.1.13, 4.5.2.11, and LCO 3.6.4.3, ‘‘Standby Gas Treatment (SGT) System.’’ The argument for staying in Mode 3 instead of going to Mode 4 to repair the SGT system (one or both trains) is also supported by defense-in-depth considerations. Section 6.2 makes a comparison between the current (Mode 3) and the proposed (Mode 4) end state, with respect to the means available to perform critical functions (i.e., functions contributing to the defense-in-depth philosophy) whose success is needed to prevent core damage and containment failure and mitigate radiation releases. The risk and defense-in-depth arguments, used according to the ‘‘integrated decision-making’’ process of Regulatory Guides 1.174 and 1.177, support the conclusion that Mode 3 is as safe as Mode 4 (if not safer) for repairing an inoperable SGT system. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. 3.2.17 TS 4.5.1.14 and LCO 3.7.1, Residual Heat Removal Service Water (RHRSW) System (BWR/4 only) The RHRSW system is designed to provide cooling water for the RHR system heat exchangers, which are required for safe shutdown following a normal shutdown or DBA or transient. [Note: Plant Applicability, BWR/4] LCO: Two RHRSW subsystems shall be operable. Condition Requiring Entry Into End State: If the LCO cannot be met, the following actions must be taken for the listed conditions: a. If one RHRSW pump is inoperable (Condition A), it must be restored to operable status within 30 days (Required Action A.1). b. If one RHRSW pump in each subsystem is inoperable (Condition B), one RHRSW pump must be restored to operable status within seven days (Required Action B.1). E:\FR\FM\14DEN1.SGM 14DEN1 74048 Federal Register / Vol. 70, No. 239 / Wednesday, December 14, 2005 / Notices c. If one RHRSW subsystem is inoperable for reasons other than Condition A (Condition C), the RHRSW subsystem must be restored to operable status within seven days (Required Action C.1). d. If the required action and associated completion time cannot be met within the allotted time (Condition E), the plant must be placed in Mode 3 within 12 hours (Required Action E.1) and in Mode 4 within 36 hours (Required Action E.2). (Note: Condition D addresses both RHRSW subsystems inoperable for reason other than Condition B, and its Required Action D.1 is not affected by this change.) Proposed Modification for End State Required Actions: Renumber Conditions D (and Required Action D.1), and E (and Required Actions E.1 and E.2), to Conditions E (and Required Action E.1) and F (and Required Actions F.1 and F.2), respectively. Modify new Condition F to address new Condition E, which maintains the existing requirements with respect to both RHR subsystems being inoperable for reasons other than Condition B. Add a new Condition D, which establishes requirements for existing Conditions A, B, and C, that are similar to existing Condition E but without Required Action E.2. Assessment: The BWROG topical report performed a comparative PRA evaluation of the core damage risks when operating in the current end state versus the proposed Mode 3 end state. The results indicated that the core damage risks while operating in Mode 3 (assuming the individual failure conditions) are lower or comparable to the current end state. By remaining in Mode 3, HPCI, RCIC, and the power conversion system (condensate/ feedwater) remain available for water makeup and decay heat removal. Additionally, the EOPs direct the operators to take control of the depressurization function if low pressure injection/spray are needed for RCS makeup and cooling. Therefore, defense-in-depth is improved with respect to water makeup and decay heat removal by remaining in Mode 3, and the required safety function can still be performed with the RHRSW subsystem components that are still operable. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. VerDate Aug<31>2005 15:29 Dec 13, 2005 Jkt 208001 3.2.18 TS 4.5.1.15 and LCO 3.7.2, Plant Service Water (PSW) System and Ultimate Heat Sink (UHS) (BWR/4 only) The PSW system (in conjunction with the UHS) is designed to provide cooling water for the removal of heat from certain safe shutdown-related equipment heat exchangers following a DBA or transient. [Note: Plant Applicability, BWR/4] LCO: Two PSW subsystems and UHS shall be operable. Condition Requiring Entry into End State: If the LCO cannot be met, the following actions must be taken for the listed conditions: a. If one PSW pump is inoperable (Condition A), it must be restored to operable status within 30 days (Required Action A.1). b. If one PSW pump in each subsystem is inoperable (Condition B), one PSW pump must be restored to operable status within seven days (Required Action B.1). c. If the required action and associated completion time cannot be met within the allotted time, the plant must be placed in Mode 3 within 12 hours (Required Action E.1) and in Mode 4 within 36 hours (Required Action E.2). Proposed Modification: Renumber unaffected Conditions C, D, E, and F to Conditions D, E, F, and G respectively, and renumber associated Required Actions accordingly. Add a new Condition C, for the Required Actions and associated Completion Time of Conditions A and B not met, with a Required Action C.1, to be in Mode 3 in a Completion Time of 12 hours. Change the new Condition G to read, ‘‘Required Action and associated Completion Time of Condition E not met, OR Both [PSW] subsystems inoperable for reasons other than Condition(s) B [and D], [OR [UHS] inoperable for reasons other than Conditions D [or E].’’ Assessment: The BWROG topical report performed a comparative PRA evaluation of the core damage risks associated with operating in the current end state versus the proposed Mode 3 end state. The results indicated that the core damage risks while operating in Mode 3 (assuming the individual failure conditions) are lower or comparable to the current end state. With one pump inoperable in one or more subsystems, the remaining pumps are adequate to perform the PSW heat removal function. By remaining in Mode 3, HPCI, RCIC, and the power conversion system (condensate/feedwater) remain available for water makeup and decay heat removal. Additionally, the EOPs direct the operators to take control of the PO 00000 Frm 00061 Fmt 4703 Sfmt 4703 depressurization function if low pressure injection/spray are needed for RCS makeup and cooling. Therefore, defense-in-depth is improved with respect to water makeup and decay heat removal by remaining in Mode 3. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. 3.2.19 TS 4.5.1.16 and LCO 3.7.4, Main Control Room Environmental Control (MCREC) System(BWR/4 only) The MCREC system provides a radiologically controlled environment from which the plant can be safely operated following a DBA. [Note: Plant Applicability, BWR/4] LCO: Two MCREC subsystems shall be operable. Condition Requiring Entry Into End State: If one MCREC subsystem is inoperable, it must be restored to operable status within seven days (Required Action A.1). If the MCREC subsystem cannot be restored to operable status within the allotted time, the plant must be placed in Mode 3 within 12 hours (Required Action B.1) and in Mode 4 within 36 hours (Required Action B.2). If two MCREC subsystems are inoperable in Mode 1, 2, or 3, LCO 3.0.3 must be entered immediately (Required Action D.1). Proposed Modification for End State Required Actions: Delete Required Action B.2, and change Required Action D.1 to ‘‘Be in Mode 3’’ with a Completion Time of ‘‘12 hours.’’ Assessment: The unavailability of one or both MCREC subsystems has no significant impact on CDF or LERF, irrespective of the mode of operation at the time of the accident. Furthermore, the challenge frequency of the MCREC system (i.e., the frequency with which the system is expected to be challenged to provide a radiologically controlled environment in the main control room following a DBA which leads to core damage and leaks of radiation from the containment that can reach the control room) is less than 1.0E–6/yr. Consequently, the conditional probability that this system will be challenged during the repair time interval while the plant is at either the current or the proposed end state (i.e., Mode 4 or Mode 3, respectively) is less than 1.0E–8. This probability is considerably smaller than probabilities considered ‘‘negligible’’ in Regulatory Guide 1.177 for much higher consequence risks, such as large early release. E:\FR\FM\14DEN1.SGM 14DEN1 Federal Register / Vol. 70, No. 239 / Wednesday, December 14, 2005 / Notices Section 6 of reference 6 summarizes the staff’s risk argument for approval of TS 4.5.1.16, and LCO 3.7.4, ‘‘Main Control Room Environmental Control (MCREC) System.’’ The argument for staying in Mode 3 instead of going to Mode 4 to repair the MCREC system (one or both trains) is also supported by defense-in-depth considerations. Section 6.2 makes a comparison between the current (Mode 3) and the proposed (Mode 4) end state, with respect to the means available to perform critical functions (i.e., functions contributing to the defense-in-depth philosophy) whose success is needed to prevent core damage and containment failure and mitigate radiation releases. The risk and defense-in-depth arguments, used according to the ‘‘integrated decision-making’’ process of Regulatory Guides 1.174 and 1.177, support the conclusion that Mode 3 is as safe as Mode 4 (if not safer) for repairing an inoperable MCREC system. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. 3.2.20 TS 4.5.1.17 and LCO 3.7.5, Control Room Air Conditioning (AC) System (BWR/4 only) The Control Room AC system provides temperature control for the control room following control room isolation during accident conditions. [Note: Plant Applicability, BWR/4] LCO: Two control room AC subsystems shall be operable. Condition Requiring Entry Into End State: If one control room AC subsystem is inoperable, the subsystem must be restored to operable status within 30 days (Required Action A.1). If the required actions and associated completion times cannot be met, the plant must be placed in Mode 3 within 12 hours (Required Action B.1) and in Mode 4 within 36 hours (Required Action B.2). If two control room AC subsystems are inoperable, LCO 3.0.3 must be entered immediately (Required Action D.1) Proposed Modification for End State Required Actions: Delete Required Action B.2, and change Required Action D.1 to ‘‘Be in Mode 3’’ with a Completion Time of ‘‘12 hours.’’ Assessment: The unavailability of one or both AC subsystems has no significant impact on CDF or LERF, irrespective of the mode of operation at the time of the accident. Furthermore, the challenge frequency of the AC system (i.e., the frequency with which VerDate Aug<31>2005 15:29 Dec 13, 2005 Jkt 208001 the system is expected to be challenged to provide temperature control for the control room following control room isolation following a DBA) is less than 1.0E–6/yr. Consequently, the conditional probability that this system will be challenged during the repair time interval while the plant is at either the current or the proposed end state (i.e., Mode 4 or Mode 3, respectively) is less than 1.0E–8. This probability is considerably smaller than probabilities considered ‘‘negligible’’ in Regulatory Guide 1.177 for much higher consequence risks, such as large early release. Section 6 of reference 6 summarizes the staff’s risk argument for approval of TS 4.5.1.17, and LCO 3.7.5, ‘‘Control Room Air Conditioning (AC) System.’’ The argument for staying in Mode 3 instead of going to Mode 4 to repair the AC system (one or both trains) is also supported by defense-in-depth considerations. Section 6.2 makes a comparison between the current (Mode 3) and the proposed (Mode 4) end state, with respect to the means available to perform critical functions (i.e., functions contributing to the defense-in-depth philosophy) whose success is needed to prevent core damage and containment failure and mitigate radiation releases. The risk and defense-in-depth arguments, used according to the ‘‘integrated decision-making’’ process of Regulatory Guides 1.174 and 1.177, support the conclusion that Mode 3 is as safe as Mode 4 (if not safer) for repairing an inoperable AC system. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. 3.2.21 TS 4.5.1.18 and LCO 3.7.6, Main Condenser Off gas (BWR/4 only) The Off gas from the main condenser normally includes radioactive gases. The gross gamma activity rate is controlled to ensure that accident analysis assumptions are satisfied and that offsite dose limits will not be exceeded during postulated accidents. The main condenser Off gas (MCOG) gross gamma activity rate is an initial condition of a DBA which assumes a gross failure of the MCOG system pressure boundary. [Note: Plant Applicability, BWR/4] LCO: The gross gamma activity rate of the noble gases measured at the main condenser evacuation system pretreatment monitor station shall be ≤240 mCi/second after decay of 30 minutes. PO 00000 Frm 00062 Fmt 4703 Sfmt 4703 74049 Condition Requiring Entry Into End State: If the gross gamma activity rate of the noble gases in the main condenser Off gas (MCOG) system is not within limits, the gross gamma activity rate of the noble gases in the main condenser Off gas must be restored to within limits within 72 hours (Required Action A.1). If the required action and associated completion time cannot be met, one of the following must occur: a. All steam lines must be isolated within 12 hours (Required Action B.1). b. The steam jet air ejector (SJAE) must be isolated within 12 hours (Required Action B.2). c. The plant must be placed in Mode 3 within 12 hours (Required Action B.3.1) and in Mode 4 within 36 hours (Required Action B.3.2). Proposed Modification for End State Required Actions: Delete Required Action B.3.2. Assessment: The failure to maintain the gross gamma activity rate of the noble gases in the main condenser Off gas (MCOG) within limits has no significant impact on CDF or LERF, irrespective of the mode of operation at the time of the accident. Furthermore, the challenge frequency of the MCOG system (i.e., the frequency with which the system is expected to be challenged to mitigate offsite radiation releases following a DBA) is less than 1.0E–6/yr. Consequently, the conditional probability that this system will be challenged during the repair time interval while the plant is at either the current or the proposed end state (i.e., Mode 4 or Mode 3, respectively) is less than 1.0E–8. This probability is considerably smaller than probabilities considered ‘‘negligible’’ in Regulatory Guide 1.177 for much higher consequence risks, such as large early release. Section 6 of reference 6 summarizes the staff’s risk argument for approval of TS 4.5.1.18 and LCO 3.7.6, ‘‘Main Condenser Off gas.’’ The argument for staying in Mode 3 instead of going to Mode 4 to repair the MCOG system (one or both trains) is also supported by defense-in-depth considerations. Section 6.2 makes a comparison between the current (Mode 3) and the proposed (Mode 4) end state, with respect to the means available to perform critical functions (i.e., functions contributing to the defense-in-depth philosophy) whose success is needed to prevent core damage and containment failure and mitigate radiation releases. The risk and defense-in-depth arguments, used according to the ‘‘integrated decision-making’’ process of Regulatory Guides 1.174 and 1.177, support the conclusion that Mode 3 is E:\FR\FM\14DEN1.SGM 14DEN1 74050 Federal Register / Vol. 70, No. 239 / Wednesday, December 14, 2005 / Notices as safe as Mode 4 (if not safer) for repairing an inoperable MCOG system. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. 3.2.22 TS 4.5.2.6 and LCO 3.6.1.7, Residual Heat Removal (RHR) Containment Spray System (BWR/6 only) The primary containment must be able to withstand a postulated bypass leakage pathway that allows the passage of steam from the drywell directly into the primary containment airspace, bypassing the suppression pool. The primary containment also must be able to withstand a low energy steam release into the primary containment airspace. The RHR Containment Spray System is designed to mitigate the effects of bypass leakage and low energy line breaks. [Note: Plant Applicability, BWR/6] LCO: Two RHR containment spray subsystems shall be operable. Condition Requiring Entry Into End State: If one RHR Containment Spray Subsystem is inoperable, it must be restored to operable status within 7 days (Required Action A.1). If two RHR Containment Spray Subsystems are inoperable, one of them must be restored to operable status within 8 hours (Required Action B.1). If the RHR Containment Spray System cannot be restored to operable status within the allotted time, the plant must be placed in Mode 3 within 12 hours (Required Action C.1), and in Mode 4 within 36 hours (Required Action C.2) Proposed Modification for End State Required Actions: Delete Required Action C.2. Assessment: The primary containment is designed with a suppression pool so that, in the event of a LOCA, steam released from the primary system is channeled through the suppression pool water and condensed without producing significant pressurization of the primary containment. The primary containment is designed so that with the pool initially at the minimum water level and the worst single failure of the primary containment heat removal systems, suppression pool energy absorption combined with subsequent operator controlled pool cooling will prevent the primary containment pressure from exceeding its design value. However, the primary containment must also withstand a postulated bypass leakage pathway that allows the passage of VerDate Aug<31>2005 15:29 Dec 13, 2005 Jkt 208001 steam from the drywell directly into the primary containment airspace, bypassing the suppression pool. The primary containment also must withstand a postulated low energy steam release into the primary containment airspace. The main function of the RHR containment spray system is to suppress steam, which is postulated to be released into the primary containment airspace through a bypass leakage pathway and a low energy line break under DBA conditions, without producing significant pressurization of the primary containment (i.e., ensure that the pressure inside primary containment remains within analyzed design limits). Under the conditions assumed in the DBA, steam blown down from the break could find its way into the primary containment through a bypass leakage pathway. In addition to the DBA, a postulated low energy pipe break could add more steam into the primary containment airspace. Under such an extremely unlikely scenario (very small frequency of a DBA combined with the likelihood of a bypass pathway and a concurrent low energy pipe brake inside the primary containment), the RHR containment spray system could be needed to condense steam so that the pressure inside the primary containment remains within analyzed design limits. Furthermore, containments have considerable margin to failure above the design limit (it is very likely that the containment will be able to withstand pressures as much as three times the design limit). For these reasons, the unavailability of one or both RHR containment spray subsystems has no significant impact on CDF or LERF, even for accidents initiated during operation at power. Therefore, it is very unlikely that the RHR containment spray system will be challenged to mitigate an accident occurring during power operation. This probability becomes extremely unlikely for accidents that would occur during a small fraction of the year (less than three days) during which the plant would be in Mode 3 (associated with lower initial energy level and reduced decay heat load as compared to power operation) to repair the failed RHR containment spray system. Section 6 of reference 6 summarizes the staff’s risk argument for approval of TS 4.5.2.6 and LCO 3.6.1.7, ‘‘Residual Heat Removal (RHR) Containment Spray System.’’ The argument for staying in Mode 3 instead of going to Mode 4 to repair the RHR containment spray system (one or both trains) is also supported by defense-in-depth considerations. Section 6.2 makes a PO 00000 Frm 00063 Fmt 4703 Sfmt 4703 comparison between the current (Mode 3) and the proposed (Mode 4) end state, with respect to the means available to perform critical functions (i.e., functions contributing to the defense-in-depth philosophy) whose success is needed to prevent core damage and containment failure and mitigate radiation releases. The risk and defense-in-depth arguments, used according to the ‘‘integrated decision-making’’ process of Regulatory Guides 1.174 and 1.177, support the conclusion that Mode 3 is as safe as Mode 4 (if not safer) for repairing an inoperable RHR containment spray system. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. 3.2.23 TS4.5.2.7 and LCO 3.6.1.8, Penetration Valve Leakage Control System (PVLCS)(BWR/6 only) The PVLCS supplements the isolation function of primary containment isolation valves (PCIVs) in process lines that also penetrate the secondary containment. These penetrations are sealed by air from the PVLCS to prevent fission products leaking past the isolation valves and bypassing the secondary containment after a design basis loss-of-coolant accident (LOCA). [Note: Plant Applicability, BWR/6] LCO: Two PVLCS subsystems shall be operable. Condition Requiring Entry Into End State: If one PVLCS subsystem is inoperable, it must be restored to operable status within 30 days (Required Action A.1). If two PVLCS subsystems are inoperable, one of the PVLCS subsystems must be restored to operable status within seven days (Required Action B.1). If the PVLCS subsystem cannot be restored to operable status within the allotted time, the plant must be placed in Mode 3 within 12 hours (Required Action C.1) and in Mode 4 within 36 hours (Required Action C.2). Assessment: The BWROG topical report has determined that this system is not significant in BWR PRAs. The unavailability of one or both PVLCS subsystems has no impact on CDF or LERF, irrespective of the mode of operation at the time of the accident. Furthermore, the challenge frequency of the PVLCS system (i.e., the frequency with which the system is expected to be challenged to prevent fission products leaking past the isolation valves and bypassing the secondary containment) is less than 1.0E–6/yr. Consequently, the E:\FR\FM\14DEN1.SGM 14DEN1 Federal Register / Vol. 70, No. 239 / Wednesday, December 14, 2005 / Notices conditional probability that this system will be challenged during the repair time interval while the plant is at either the current or the proposed end state (i.e., Mode 4 or Mode 3, respectively) is less than 1.0E–8. This probability is considerably smaller than probabilities considered ‘‘negligible’’ in Regulatory Guide 1.177 for much higher consequence risks, such as large early release. Section 6 of reference 6 summarizes the staff’s risk argument for approval of TS 4.5.2.7 and LCO 3.6.1.8, ‘‘Penetration Valve Leakage Control System (PVLCS).’’ The argument for staying in Mode 3 instead of going to Mode 4 to repair the PVLCS system (one or both trains) is also supported by defense-indepth considerations. Section 6.2 makes a comparison between the current (Mode 3) and the proposed (Mode 4) end state, with respect to the means available to perform critical functions (i.e., functions contributing to the defense-in-depth philosophy) whose success is needed to prevent core damage and containment failure and mitigate radiation releases. The risk and defense-in-depth arguments, used according to the ‘‘integrated decisionmaking’’ process of Regulatory Guides 1.174 and 1.177, support the conclusion that Mode 3 is as safe as Mode 4 (if not safer) for repairing an inoperable PVLCS system. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. 3.2.24 TS 4.5.1.10, TS 4.5.2.9 and LCO 3.6.2.3, Residual Heat Removal (RHR) Suppression Pool Cooling Some means must be provided to remove heat from the suppression pool so that the temperature inside the primary containment remains within design limits. This function is provided by two redundant RHR suppression pool cooling subsystems. [Note: Plant Applicability, BWR 4/6] LCO: Two RHR suppression pool cooling subsystems shall be operable. Condition Requiring Entry Into End State: If one RHR suppression pool cooling subsystem is inoperable (Condition A), it must be restored to operable status within seven days (Required Action A.1). If the RHR suppression pool spray subsystem cannot be restored to operable status within the allotted time (Condition B), the plant must be placed in Mode 3 within 12 hours (Required Action B.1), VerDate Aug<31>2005 15:29 Dec 13, 2005 Jkt 208001 and in Mode 4 within 36 hours (Required Action B.2). Proposed Modification for End State Required Actions: Delete Required Action B.2, and retain Condition B and Required Action B.1 for one RHR suppression pool spray subsystem inoperable. Add Condition C, with Required Actions C.1 and C.2, identical to existing Condition B, with Required Actions B.1 and B.2, to maintain existing requirements unchanged for two RHR suppression pool subsystems inoperable. Assessment: The BWROG topical report has completed a comparative PRA evaluation of the core damage risks of operation in the current end state versus operation in the proposed Mode 3 end state. The results indicated that the core damage risks while operating in Mode 3 (assuming the individual failure conditions) are lower or comparable to the current end state. One loop of the RHR suppression pool cooling system is sufficient to accomplish the required safety function. By remaining in Mode 3, HPCS, RCIC, and the power conversion system (condensate/ feedwater) remain available for water makeup and decay heat removal. Additionally, the EOPs direct the operators to take control of the depressurization function if low pressure injection/spray are needed for RCS makeup and cooling. Therefore, defense-in-depth is improved with respect to water makeup and decay heat removal by remaining in Mode 3. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. 3.2.25 TS 4.5.2.12 and LCO 3.6.5.6, Drywell Vacuum Relief System (BWR/6 only) The Mark III pressure suppression containment is designed to condense, in the suppression pool, the steam released into the drywell in the event of a lossof-coolant accident (LOCA). The steam discharging to the pool carries the noncondensibles from the drywell. Therefore, the drywell atmosphere changes from low humidity air to nearly 100% steam (no air) as the event progresses. When the drywell subsequently cools and depressurizes, non-condensibles in the drywell must be replaced to avoid excessive weir wall overflow into the drywell. Rapid weir wall overflow must be controlled in a large break LOCA, so that essential equipment and systems located above the weir wall in the drywell are not subjected to excessive drag and impact PO 00000 Frm 00064 Fmt 4703 Sfmt 4703 74051 loads. The drywell post-LOCA and the drywell purge vacuum relief subsystems are the means by which noncondensibles are transferred from the primary containment back to the drywell. [Note: Plant Applicability, BWR/6] LCO: Two drywell post-LOCA and two drywell purge vacuum relief subsystems shall be operable. Condition Requiring Entry Into End State: If one or two drywell post-LOCA vacuum relief subsystems are inoperable (Condition A), or if one drywell purge vacuum relief subsystem is inoperable (Condition B), for reasons other than being not closed, the subsystem(s) must be restored to operable status within 30 days (Required Actions B.1 and C.1, respectively). If the required actions cannot be completed within the allotted time, the plant must be placed in Mode 3 within 12 hours and in Mode 4 within 36 hours. Proposed Modification for End State Required Actions: Renumber Conditions D, E, F and G, to Conditions E, F, G, and H respectively, and renumber associated Required Actions accordingly. Add a new Condition D for when Required Action and Associated Completion Time of Condition B or C not met, with Required Action D.1 to be in Mode 3 in a Completion Time of 12 hours. Change new Condition G to read, ‘‘Required Action and Associated Completion Time of Condition A, E or F not met.’’ Assessment: The BWROG topical report has determined that the specific failure conditions of interest are not risk significant in BWR PRAs. With one or two drywell post-LOCA vacuum relief subsystems inoperable or one drywell purge vacuum relief subsystem inoperable, for reasons other than not being closed, the remaining operable vacuum relief subsystems are adequate to perform the depressurization mitigation function. By remaining in Mode 3, HPCS, RCIC, and the power conversion system (condensate/ feedwater) remain available for water makeup and decay heat removal. Additionally, the EOPs direct the operators to take control of the depressurization function if low pressure injection/spray are needed for RCS makeup and cooling. Therefore, defense-in-depth is improved with respect to water makeup and decay heat removal by remaining in Mode 3. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. E:\FR\FM\14DEN1.SGM 14DEN1 74052 Federal Register / Vol. 70, No. 239 / Wednesday, December 14, 2005 / Notices 3.2.26 TS 4.5.2.13 and LCO 3.7.1, Standby Service Water (SSW) System and Ultimate Heat Sink (UHS)(BWR/6 only) The SSW system (in conjunction with the UHS) is designed to provide cooling water for the removal of heat from certain safe shutdown-related equipment heat exchangers following a DBA or transient. [Note: Plant Applicability, BWR/6] LCO: Division 1 and 2 SSW subsystems and UHS shall be operable. Condition Requiring Entry Into End State: If one or more cooling towers with one cooling tower fan is inoperable (Condition A), the cooling tower fan(s) must be restored to operable status within seven days (Required Action A.1). If one SSW subsystem is inoperable for reasons other than Condition A (Condition C), the SSW subsystem must be restored to operable status within 72 hours (Required Action C.1). If the required action(s) and associated completion time(s) (of Conditions A or C) cannot be met (Condition D), the plant must be placed in Mode 3 within 12 hours (Required Action D.1) and in Mode 4 within 36 hours (Required Action D.2). Proposed Modification: The existing second and third conditions of existing Condition D have been transferred to a new Condition E in an unchanged form (with Required Actions E.1 and E.2 identical to existing Required Actions D.1 and D.2). Existing Condition B with its associated Required Actions and Associated Completion Times, has been transferred to a new Condition D in an unchanged form. Existing Condition C, with its associated Required Action and Associated Completion Time, has been moved to a new Condition B in unchanged form. A new Condition C has been created. If the Required Actions and Associated Completion Times for new Condition A or B are not met (new Condition C), then the plant must be placed in Mode 3 in 12 hours (new Required Action C.1). Assessment: The BWROG topical report determined that the specific failure condition of interest is not risk significant in BWR PRAs. With the specified inoperable components/ subsystems, a sufficient number of operable components/subsystems are still available to perform the heat removal function. By remaining in Mode 3, HPCS, RCIC, and the power conversion system (condensate/ feedwater) remain available for water makeup and decay heat removal. Additionally, the EOPs direct the operators to take control of the depressurization function if low VerDate Aug<31>2005 15:29 Dec 13, 2005 Jkt 208001 pressure injection/spray are needed for RCS makeup and cooling. Therefore, defense-in-depth is improved with respect to water makeup and decay heat removal by remaining in Mode 3. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. 3.2.27 TS 4.5.2.14 and LCO 3.7.3, Control Room Fresh Air (CRFA) System (BWR/6 only) The CRFA system provides a radiologically controlled environment from which the unit can be safely operated following a DBA. The CRFA system consists of two independent and redundant high efficiency air filtration subsystems for treatment of recirculated air or outside supply air. Each subsystem consists of a demister, an electric heater, a prefilter, a high efficiency particulate air (HEPA) filter, an activated charcoal adsorber section, a second HEPA filter, a fan, and the associated ductwork and dampers. Demisters remove water droplets from the airstream. Prefilters and HEPA filters remove particulate matter that may be radioactive. The charcoal adsorbers provide a holdup period for gaseous iodine, allowing time for decay. [Note: Plant Applicability, BWR/6] LCO: Two CRFA subsystems shall be operable. Condition Requiring Entry Into End State: If one CRFA subsystem is inoperable (Condition A), it must be restored to operable status within seven days (Required Action A.1). If two CRFA subsystems are inoperable (Condition B for control room boundary and Condition E for reasons for inoperability), one CRFA subsystem must be restored to operable status in 24 hours (Required Action B.1) or enter LCO 3.0.3 (Required Action E.1). If Conditions A or B, and associated Required Actions A.1 and B.1) cannot be met in the required Completion Time (Condition C), the plant must be placed in Mode 3 within 12 hours (Required Action C.1) and in Mode 4 within 36 hours (Required Action C.2). Proposed Modification for End State Required Actions: Delete Required Action C.2, and change Required Action E.1 to ‘‘Be in Mode 3’’ within a Completion Time of ‘‘12 hours.’’ Assessment: The unavailability of one or both CRFA subsystems has no significant impact on CDF or LERF, irrespective of the mode of operation at the time of the accident. Furthermore, the challenge frequency of the CRFA PO 00000 Frm 00065 Fmt 4703 Sfmt 4703 system (i.e., the frequency with which the system is expected to be challenged to provide a radiologically controlled environment in the main control room following a DBA which leads to core damage and leaks of radiation from the containment that can reach the control room) is less than 1.0E–6/yr. Consequently, the conditional probability that this system will be challenged during the repair time interval while the plant is at either the current or the proposed end state (i.e., Mode 4 or Mode 3, respectively) is less than 1.0E–8. This probability is considerably smaller than probabilities considered ‘‘negligible’’ in Regulatory Guide 1.177 for much higher consequence risks, such as large early release. Section 6 of reference 6 summarizes the staff’s risk argument for approval of TS 4.5.2.14 and LCO 3.7.3, ‘‘Control Room Fresh Air (CRFA) System.’’ The argument for staying in Mode 3 instead of going to Mode 4 to repair the CRFA system (one or both trains) is also supported by defense-in-depth considerations. Section 6.2 makes a comparison between the current (Mode 3) and the proposed (Mode 4) end state, with respect to the means available to perform critical functions (i.e., functions contributing to the defense-in-depth philosophy) whose success is needed to prevent core damage and containment failure and mitigate radiation releases. The risk and defense-in-depth arguments, used according to the ‘‘integrated decision-making’’ process of Regulatory Guides 1.174 and 1.177, support the conclusion that Mode 3 is as safe as Mode 4 (if not safer) for repairing an inoperable CRFA system. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. 3.2.28 TS 4.5.2.15 and LCO 3.7.4, Control Room Air Conditioning (CRAC) System (BWR/6 only) The control room AC system provides temperature control for the control room following control room isolation. The control room AC system consists of two independent, redundant subsystems that provide cooling and heating of recirculated control room air. Each subsystem consists of heating coils, cooling coils, fans, chillers, compressors, ductwork, dampers, and instrumentation and controls to provide for control room temperature control. The control room AC system is designed to provide a controlled environment under both normal and accident E:\FR\FM\14DEN1.SGM 14DEN1 Federal Register / Vol. 70, No. 239 / Wednesday, December 14, 2005 / Notices conditions. A single subsystem provides the required temperature control to maintain a suitable control room environment for a sustained occupancy of 12 persons. [Note: Plant Applicability, BWR/6] LCO: Two control room AC subsystems shall be operable. Condition Requiring Entry Into End State: If one control room AC subsystem is inoperable, it must be restored to operable status within 30 days (Required Action A.1). If the required actions and associated completion times cannot be met, the plant must be placed in Mode 3 within 12 hours (Required Action B.1) and in Mode 4 within 36 hours (Required Action B.2). If two control room AC subsystems are inoperable, LCO 3.0.3 must be entered immediately (Condition D). Proposed Modification for End State Required Actions: Delete Required Action B.2, and change Required Action D.1 to ‘‘Be in Mode 3’’ with a Completion Time of ‘‘12 hours.’’ Assessment: The unavailability of one or both AC subsystems has no significant impact on CDF or LERF, irrespective of the mode of operation at the time of the accident. Furthermore, the challenge frequency of the AC system (i.e., the frequency with which the system is expected to be challenged to provide temperature control for the control room following control room isolation following a DBA which leads to core damage) is less than 1.0E–6/yr. Consequently, the conditional probability that this system will be challenged during the repair time interval while the plant is at either the current or the proposed end state (i.e., Mode 4 or Mode 3, respectively) is less than 1.0E–8. This probability is considerably smaller than probabilities considered ‘‘negligible’’ in Regulatory Guide 1.177 for much higher consequence risks, such as large early release. Section 6 of reference 6 summarizes the staff’s risk argument for approval of TS 4.5.2.15 and LCO 3.7.4, ‘‘Control Room Air Conditioning (AC) System.’’ The argument for staying in Mode 3 instead of going to Mode 4 to repair the CRAC system (one or both trains) is also supported by defense-in-depth considerations. Section 6.2 makes a comparison between the current (Mode 3) and the proposed (Mode 4) end state, with respect to the means available to perform critical functions (i.e., functions contributing to the defense-in-depth philosophy) whose success is needed to prevent core damage and containment failure and mitigate radiation releases. The risk and defense-in-depth VerDate Aug<31>2005 15:29 Dec 13, 2005 Jkt 208001 arguments, used according to the ‘‘integrated decision-making’’ process of Regulatory Guides 1.174 and 1.177, support the conclusion that Mode 3 is as safe as Mode 4 (if not safer) for repairing an inoperable CRAC system. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. 3.2.29 TS 4.5.2.16 and LCO 3.7.5, Main Condenser Off gas (BWR/6 only) The Off gas from the main condenser normally includes radioactive gases. The gross gamma activity rate is controlled to ensure that accident analysis assumptions are satisfied and that offsite dose limits will not be exceeded during postulated accidents. [Note: Plant Applicability, BWR/6] LCO: The gross gamma activity rate of the noble gases measured at the Off gas recombiner effluent shall be ≤380 mCi/ second after decay of 30 minutes. Condition Requiring Entry Into End State: If the gross gamma activity rate of the noble gases in the main condenser Off gas is not within limits (Condition A), the gross gamma activity rate of the noble gases in the main condenser Off gas must be restored to within limits within 72 hours (Required Action A.1). If the required action and associated completion time cannot be met, one of the following must occur: a. All steam lines must be isolated within 12 hours (Required Action B.1). b. The steam jet air ejector (SJAE) must be isolated within 12 hours (Required Action B.2). c. The plant must be placed in Mode 3 within 12 hours (Required Action B.3.1) and in Mode 4 within 36 hours (Required Action B.3.2). Proposed Modification for End State Required Actions: Delete Required Action B.3.2. Assessment: The failure to maintain the gross gamma activity rate of the noble gases in the main condenser Off gas (MCOG) within limits has no significant impact on CDF or LERF, irrespective of the mode of operation at the time of the accident. Furthermore, the challenge frequency of the MCOG system (i.e., the frequency with which the system is expected to be challenged to mitigate offsite radiation releases following a DBA) is less than 1.0E–6/yr. Consequently, the conditional probability that this system will be challenged during the repair time interval while the plant is at either the current or the proposed end state (i.e., Mode 4 or Mode 3, respectively) is less PO 00000 Frm 00066 Fmt 4703 Sfmt 4703 74053 than 1.0E–8. This probability is considerably smaller than probabilities considered ‘‘negligible’’ in Regulatory Guide 1.177 for much higher consequence risks, such as large early release. Section 6 of reference 6 summarizes the staff’s risk argument for approval of TS 4.5.2.16 and LCO 3.7.5, ‘‘Main Condenser Off gas.’’ The argument for staying in Mode 3 instead of going to Mode 4 to repair the MCOG system (one or both trains) is also supported by defense-in-depth considerations. Section 6.2 makes a comparison between the current (Mode 3) and the proposed (Mode 4) end state, with respect to the means available to perform critical functions (i.e., functions contributing to the defense-in-depth philosophy) whose success is needed to prevent core damage and containment failure and mitigate radiation releases. The risk and defense-in-depth arguments, used according to the ‘‘integrated decision-making’’ process of Regulatory Guides 1.174 and 1.177, support the conclusion that Mode 3 is as safe as Mode 4 (if not safer) for repairing an inoperable MCOG system. Finding: Based upon the above assessment, and because the time spent in Mode 3 to perform the repair is infrequent and limited, and in light of defense-in-depth considerations, the proposed change is acceptable. 4.0 State Consultation In accordance with the Commission’s regulations, the [__] State official was notified of the proposed issuance of the amendment. The State official had [(1) no comments or (2) the following comments—with subsequent disposition by the staff]. 5.0 Environmental Consideration The amendment changes requirements with respect to the installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. [For licensees adding a Bases Control Program: The amendment also changes record keeping, reporting, or administrative procedures or requirements.] The NRC staff has determined that the amendment involves no significant increase in the amounts and no significant change in the types of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendment involves no significant hazards considerations, and there has been no public comment on E:\FR\FM\14DEN1.SGM 14DEN1 74054 Federal Register / Vol. 70, No. 239 / Wednesday, December 14, 2005 / Notices the finding [FR ]. Accordingly, the amendments meet the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9) [and (c)(10)]. Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendment. 6.0 Conclusion The Commission has concluded, on the basis of the considerations discussed above, that (1) There is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission’s regulations, and (3) the issuance of the amendments will not be inimical to the common defense and security or to the health and safety of the public. 7.0 References 1. NEDC–32988–A, Revision 2, ‘‘Technical Justification to Support Risk-Informed Modification to Selected Required Action End States for BWR Plants,’’ September 2005. 2. Federal Register, Vol. 58, No. 139, p. 39136, ‘‘Final Policy Statement on Technical Specifications Improvements for Nuclear Power Plants,’’ July 22, 1993. 3. 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants.’’ 4. Regulatory Guide 1.182, ‘‘Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants,’’ May 2000. (ML003699426) 5. NUMARC 93–01, ‘‘Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants,’’ Nuclear Management and Resource Council, Revision 3, July 2000. 6. NRC Safety Evaluation for Topical Report NEDC–32988, Revision 2, September 27, 2002. (ML022700603) 7. TSTF–423, Revision 0, ‘‘Technical Specifications End States, NEDC– 32988–A.’’ 8. TSTF–IG–05–02, Implementation Guidance for TSTF–423, Revision 0, ‘‘Technical Specifications End States, NEDC–32988–A,’’ September 2005. 9. Regulatory Guide 1.174, ‘‘An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decision Making on Plant Specific Changes to the Licensing Basis,’’ USNRC, August 1998. (ML003740133) 10. Regulatory Guide 1.177, ‘‘An Approach for Pant Specific RiskInformed Decision Making: Technical Specifications,’’ USNRC, August 1998. (ML003740176) VerDate Aug<31>2005 15:29 Dec 13, 2005 Jkt 208001 Proposed No Significant Hazards Consideration Determination Description of Amendment Request: A change is proposed to the technical specifications (TS) of [plant name], consistent with Technical Specifications Task Force (TSTF) change TSTF–423 to the standard technical specifications (STS) for BWR Plants (NUREG 1433 and NUREG 1434) to allow, for some systems, entry into hot shutdown rather than cold shutdown to repair equipment, if risk is assessed and managed consistent with the program in place for complying with the requirements of 10 CFR 50.65(a)(4). Changes proposed in will be made to the [plant name] TS for selected Required Action end states providing this allowance. Basis for proposed no-significanthazards-consideration determination: As required by 10 CFR 50.91(a), an analysis of the issue of no-significanthazards-consideration is presented below: Criterion 1—The Proposed Change Does Not Involve a Significant Increase in the Probability or Consequences of an Accident Previously Evaluated The proposed change allows a change to certain required end states when the TS Completion Times for remaining in power operation will be exceeded. Most of the requested technical specification (TS) changes are to permit an end state of hot shutdown (Mode 3) rather than an end state of cold shutdown (Mode 4) contained in the current TS. The request was limited to: (1) Those end states where entry into the shutdown mode is for a short interval, (2) entry is initiated by inoperability of a single train of equipment or a restriction on a plant operational parameter, unless otherwise stated in the applicable technical specification, and (3) the primary purpose is to correct the initiating condition and return to power operation as soon as is practical. Risk insights from both the qualitative and quantitative risk assessments were used in specific TS assessments. Such assessments are documented in Section 6 of GE NEDC–32988, Revision 2, ‘‘Technical Justification to support Risk Informed Modification to Selected Required Action End States for BWR Plants.’’ They provide an integrated discussion of deterministic and probabilistic issues, focusing on specific technical specifications, which are used to support the proposed TS end state and associated restrictions. The staff finds that the risk insights support the conclusions of the specific TS assessments. Therefore, the probability PO 00000 Frm 00067 Fmt 4703 Sfmt 4703 of an accident previously evaluated is not significantly increased, if at all. The consequences of an accident after adopting proposed TSTF–423, are no different than the consequences of an accident prior to adopting TSTF–423. Therefore, the consequences of an accident previously evaluated are not significantly affected by this change. The addition of a requirement to assess and manage the risk introduced by this change will further minimize possible concerns. Therefore, this change does not involve a significant increase in the probability or consequences of an accident previously evaluated. Criterion 2—The Proposed Change Does Not Create the Possibility of a New or Different Kind of Accident From Any Previously Evaluated The proposed change does not involve a physical alteration of the plant (no new or different type of equipment will be installed). If risk is assessed and managed, allowing a change to certain required end states when the TS Completion Times for remaining in power operation are exceeded, i.e., entry into hot shutdown rather than cold shutdown to repair equipment, will not introduce new failure modes or effects and will not, in the absence of other unrelated failures, lead to an accident whose consequences exceed the consequences of accidents previously evaluated. The addition of a requirement to assess and manage the risk introduced by this change and the commitment by the licensee to adhere to the guidance in TSTF–IG–05–02, Implementation Guidance for TSTF– 423, Revision 0, ‘‘Technical Specifications End States, NEDC– 32988–A,’’ will further minimize possible concerns. Thus, this change does not create the possibility of a new or different kind of accident from an accident previously evaluated. Criterion 3—The Proposed Change Does Not Involve a Significant Reduction in the Margin of Safety The proposed change allows, for some systems, entry into hot shutdown rather than cold shutdown to repair equipment, if risk is assessed and managed. The BWROG’s risk assessment approach is comprehensive and follows staff guidance as documented in RGs 1.174 and 1.177. In addition, the analyses show that the criteria of the three-tiered approach for allowing TS changes are met. The risk impact of the proposed TS changes was assessed following the three-tiered approach recommended in RG 1.177. A risk assessment was performed to justify the proposed TS changes. The net change to E:\FR\FM\14DEN1.SGM 14DEN1 Federal Register / Vol. 70, No. 239 / Wednesday, December 14, 2005 / Notices the margin of safety is insignificant. Therefore, this change does not involve a significant reduction in a margin of safety. Based upon the reasoning presented above and the previous discussion of the amendment request, the requested change does not involve a significant hazards consideration. Dated at Rockville, Maryland, this 8th day of December, 2005. For the Nuclear Regulatory Commission. T. Robert Tjader, Sr., Acting Branch Chief, Technical Specifications Branch, Division of Inspection & Regional Support, Associate Director for Operating Reactor Oversight & Licensing, Office of Nuclear Reactor Regulation. [FR Doc. 05–24021 Filed 12–13–05; 8:45 am] BILLING CODE 7590–01–P SECURITIES AND EXCHANGE COMMISSION [Release No. IC–27184; 812–13176] The Integrity Funds, et al.; Notice of Application December 8, 2005. Securities and Exchange Commission (‘‘Commission’’). ACTION: Notice of an application for an order under section 12(d)(1)(J) of the Investment Company Act of 1940 (‘‘Act’’) for an exemption from section 12(d)(1)(F)(ii) of the Act. AGENCY: Summary of Application: Applicants request an order to permit certain registered open-end management investment companies relying on section 12(d)(1)(F) of the Act to charge a sales load in excess of 11⁄2 percent. Applicants: Integrity Money Management, Inc. (the ‘‘Adviser’’), Integrity Funds Distributor, Inc. (the ‘‘Distributor’’), and The Integrity Funds on behalf of itself and certain series thereof, and future registered open-end management investment companies and series thereof advised by the Adviser or an entity controlling, controlled by, or under common control with the Adviser or for which the Distributor or any entity controlling, controlled by, or under common control with the Distributor serves as principal underwriter (the ‘‘Funds’’). Filing Dates: The application was filed on March 17, 2005 and amended on December 2, 2005. Hearing or Notification of Hearing: An order granting the application will be issued unless the Commission orders a hearing. Interested persons may request a hearing by writing to the Commission’s Secretary and serving VerDate Aug<31>2005 15:29 Dec 13, 2005 Jkt 208001 applicants with a copy of the request, personally or by mail. Hearing requests should be received by the Commission by 5:30 p.m. on January 3, 2006 and should be accompanied by proof of service on the applicants, in the form of an affidavit or, for lawyers, a certificate of service. Hearing requests should state the nature of the writer’s interest, the reason for the request, and the issues contested. Persons who wish to be notified of a hearing may request notification by writing to the Commission’s Secretary. ADDRESSES: Secretary, U.S. Securities and Exchange Commission, 100 F Street, NE., Washington, DC 20549– 9303; Applicants: Brenda Sem, c/o Integrity Mutual Funds, Inc., 1 Main Street North, Minot, North Dakota 58703. FOR FURTHER INFORMATION CONTACT: Keith A. Gregory, Senior Counsel, at (202) 551–6815 or Mary Kay Frech, Branch Chief, at (202) 551–6821 (Division of Investment Management, Office of Investment Company Regulation). SUPPLEMENTARY INFORMATION: The following is a summary of the application. The complete application may be obtained for a fee at the Commission’s Public Reference Desk, 100 F Street, NE., Washington, DC 20549–0102 (tel. (202) 551–8090). Applicants’ Representations 1. The Integrity Funds is a Delaware statutory trust registered with the Commission under the Act as an openend management investment company. The Integrity Funds currently consists of ten Funds.1 The Adviser is registered as an investment adviser under the Investment Advisers Act of 1940. The Distributor is the principal underwriter to the Funds and is registered as a broker-dealer under the Securities Exchange Act of 1934. 2. Certain Funds, including the All Season Fund, intend to invest all or a portion of their assets in the shares of various other registered investment companies that are not part of the same ‘‘group of investment companies’’ as defined in section 12(d)(1)(G)(ii) of the Act as the Funds (‘‘Underlying Funds’’) in reliance on section 12(d)(1)(F) of the Act. Each of the Underlying Funds will be registered as a closed-end investment company, an open-end investment 1 The Integrity All Season Fund (the ‘‘All Season Fund’’) is the only existing Fund that currently intends to rely on the requested relief. Any existing or future registered open-end management investment company or series thereof that relies on the order in the future will do so only in accordance with the terms and conditions of the application. PO 00000 Frm 00068 Fmt 4703 Sfmt 4703 74055 company or unit investment trust. The Underlying Funds may also be registered as open-end investment companies or unit investment trusts that have received exemptive relief to, among other things, issue shares of limited redeemability that can be traded on an exchange at negotiated prices (‘‘Exchange-Traded Funds’’). The Funds also may invest a portion of their assets directly in equity or fixed income securities, and other investments. Applicants request relief to permit the Funds to charge a sales load in excess of the limit in section 12(d)(1)(F)(ii) of the Act. Applicants’ Legal Analysis A. Section 12(d)(1) of the Act 1. Section 12(d)(1)(A) of the Act provides that no registered investment company may acquire securities of another investment company if those securities represent more than 3% of the acquired company’s total outstanding voting stock, more than 5% of the acquiring company’s total assets, or if the securities, together with the securities of any other acquired investment companies, represent more than 10% of the acquiring company’s total assets. Section 12(d)(1)(B) of the Act provides that no registered openend investment company, its principal underwriter and any broker or dealer may sell securities of the company to another investment company if the sale will cause the acquiring company to own more than 3% of the acquired company’s voting stock, or if the sale will cause more than 10% of the acquired company’s voting stock to be owned by investment companies. 2. Section 12(d)(1)(F) of the Act provides that section 12(d)(1) shall not apply to the acquisition by a registered investment company of the securities of an investment company if, among other things, the acquiring company and its affiliates immediately after the purchase own no more than 3% of an acquired company’s total outstanding stock and the acquiring company does not charge a sales load in excess of 11⁄2%. Applicants state that the Funds will comply with section 12(d)(1)(F) in all respects except for the sales load limit of 11⁄2%. 3. Section 12(d)(1)(J) of the Act provides that the Commission may exempt persons or transactions from any provision of section 12(d)(1), if and to the extent that such exemption is consistent with the public interest and the protection of investors. 4. Applicants request an order under section 12(d)(1)(J) exempting them from the sales load limitation in section E:\FR\FM\14DEN1.SGM 14DEN1

Agencies

[Federal Register Volume 70, Number 239 (Wednesday, December 14, 2005)]
[Notices]
[Pages 74037-74055]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 05-24021]


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NUCLEAR REGULATORY COMMISSION


Notice of Opportunity To Comment on Model Safety Evaluation on 
Technical Specification Improvement for Boiling Water Reactor Plants; 
to Risk-Inform Requirements Regarding Selected Required Action End 
States Using the Consolidated Line Item Improvement Process

AGENCY: Nuclear Regulatory Commission.

ACTION: Request for comment.

-----------------------------------------------------------------------

SUMMARY: Notice is hereby given that the staff of the Nuclear 
Regulatory Commission (NRC) has prepared a model safety evaluation (SE) 
relating to changes to end state requirements for required actions in 
Boiling Water Reactor (BWR) plants' technical specifications (TS). The 
NRC staff has also prepared a model no-significant-hazards-
consideration (NSHC) determination relating to this matter. The purpose 
of these models is to permit the NRC to efficiently process amendments 
that propose to adopt technical specifications changes, designated as 
TSTF-423, related to Topical Report GE NEDC-32988, Revision 2, 
``Technical Justification to support Risk Informed Modification to 
Selected Required Action End States for BWR Plants,'' which was 
approved by an NRC SE dated September 27, 2002. Licensees of BWR 
nuclear power reactors to which the models apply could then request 
amendments, confirming the applicability of the SE and NSHC 
determination to their reactors. The NRC staff is requesting comment on 
the model SE and model NSHC determination prior to announcing their 
availability for referencing in license amendment applications.

DATES: The comment period expires January 13, 2006. Comments received 
after this date will be considered if it is practical to do so, but the 
Commission is able to ensure consideration only for comments received 
on or before this date.

ADDRESSES: Comments may be submitted either electronically or via U.S. 
mail. Comments may be submitted by electronic mail to CLIIP@nrc.gov. 
Submit written comments to Chief, Rules and Directives Branch, Division 
of Administrative Services, Office of Administration, Mail Stop: T-6 
D59, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001. 
Hand deliver comments to: 11545 Rockville Pike, Rockville, Maryland, 
between 7:45 a.m. and 4:15 p.m. on Federal workdays. Copies of comments 
received may be examined at the NRC's Public Document Room, 11555 
Rockville Pike (Room O-1F21), Rockville, Maryland.

FOR FURTHER INFORMATION CONTACT: T. R. Tjader, Mail Stop: O-12H2, 
Division of Inspection and Regional Support, Office of Nuclear Reactor 
Regulation, U.S. Nuclear Regulatory Commission, Washington, DC 20555-
0001, telephone 301-415-1187.

SUPPLEMENTARY INFORMATION:

Background

    Regulatory Issue Summary 2000-06, ``Consolidated Line Item 
Improvement Process for Adopting Standard Technical Specification 
Changes for Power Reactors,'' was issued on March

[[Page 74038]]

20, 2000. The consolidated line item improvement process (CLIIP) is 
intended to improve the efficiency of NRC licensing processes, by 
processing proposed changes to the standard technical specifications 
(STS) in a manner that supports subsequent license amendment 
applications. The CLIIP includes an opportunity for the public to 
comment on proposed changes to the STS after a preliminary assessment 
by the NRC staff and finding that the change will likely be offered for 
adoption by licensees. The CLIIP directs the NRC staff to evaluate any 
comments received for a proposed change to the STS and to either 
reconsider the change or announce the availability of the change for 
adoption by licensees. Licensees opting to apply for this TS change are 
responsible for reviewing the staff's evaluation, referencing the 
applicable technical justifications, and providing any necessary plant-
specific information. Each amendment application made in response to 
the notice of availability will be processed and noticed in accordance 
with applicable NRC rules and procedures.
    This notice solicits comment on changes to end state requirements 
for required actions, if risk is assessed and managed, for the primary 
purpose of accomplishing short-duration repairs which necessitated 
exiting the original Mode of operation. The change was proposed in 
Topical Report GE NEDC-32988, Revision 2, ``Technical Justification to 
support Risk Informed Modification to Selected Required Action End 
States for BWR Plants,'' which was approved by an NRC SE dated 
September 27, 2002. This change was proposed for incorporation into the 
standard technical specifications by the owners groups participants in 
the Technical Specification Task Force (TSTF) and is designated TSTF-
423. TSTF-423 can be viewed on the NRC's Web page at http://
www.nrc.gov/reactors/operating/licensing/techspecs.html.

Applicability

    This proposal to modify technical specification requirements by the 
adoption of TSTF-423 is applicable to all licensees of BWR plants who 
have adopted or will adopt, in conjunction with the proposed change, 
technical specification requirements for a Bases control program 
consistent with the TS Bases Control Program described in Section 5.5 
of the applicable vendor's STS.
    To efficiently process the incoming license amendment applications, 
the staff requests that each licensee applying for the changes proposed 
in TSTF-423 include Bases for the proposed TS consistent with the Bases 
proposed in TSTF-423. In addition, licensees that have not adopted 
requirements for a Bases control program by converting to the improved 
STS or by other means, are requested to include the requirements for a 
Bases control program consistent with the STS in their application for 
the proposed change. The need for a Bases control program stems from 
the need for adequate regulatory control of some key elements of the 
proposal that are contained in the proposed Bases in TSTF-423. The 
staff is requesting that the Bases be included with the proposed 
license amendments in this case because the changes to the TS and the 
changes to the associated Bases form an integral change to a plant's 
licensing bases. To ensure that the overall change, including the 
Bases, includes appropriate regulatory controls, the staff plans to 
condition the issuance of each license amendment on the licensee's 
incorporation of the changes into the Bases document and on requiring 
the licensee to control the changes in accordance with the Bases 
Control Program. The CLIIP does not prevent licensees from requesting 
an alternative approach or proposing the changes without the requested 
Bases and Bases control program. However, deviations from the approach 
recommended in this notice may require additional review by the NRC 
staff and may increase the time and resources needed for the review.

Public Notices

    This notice requests comments from interested members of the public 
within 30 days of the date of publication in the Federal Register. 
After evaluating the comments received as a result of this notice, the 
staff will either reconsider the proposed change or announce the 
availability of the change in a subsequent notice (perhaps with some 
changes to the safety evaluation or the proposed NSHC determination as 
a result of public comments). If the staff announces the availability 
of the change, licensees wishing to adopt the change must submit an 
application in accordance with applicable rules and other regulatory 
requirements. For each application, the staff will publish a notice of 
consideration of issuance of amendment to facility operating licenses, 
a proposed NSHC determination, and a notice of opportunity for a 
hearing. The staff will also publish a notice of issuance of an 
amendment to operating license to announce the modification of end 
state requirements for required actions in plant technical 
specifications.

Proposed Model Plant Specific Safety Evaluation for Technical 
Specification Task Force (TSTF) Change TSTF-423, Risk Informed 
Modification to Selected Required Action End States, a Consolidated 
Line Item Improvement

Safety Evaluation by the Office of Nuclear Reactor Regulation; Related 
to Amendment No. [----] to Facility Operating License NFP-[----], 
[Utility Name], [Plant Name], [Unit----], Docket No.-[----]

1.0 Introduction

    By letter dated --------, 20 --, [Utility Name] (the licensee) 
proposed changes to the technical specifications (TS) for [plant name]. 
The requested changes are the adoption of TSTF-423, Revision 0, to the 
Boiling Water Reactor (BWR) Standard Technical Specifications (STS) 
(NUREG 1433 and NUREG 1434), which was proposed by the Nuclear Energy 
Institute (NEI) Risk Informed Technical Specifications Task Force 
(RITSTF) on August 12, 2003, on behalf of the industry. TSTF-423, 
Revision 0, incorporates the BWR Owners Group (BWROG) approved Topical 
Report NEDC-32988, Revision 2, ``Technical Justification to Support 
Risk Informed Modification to Selected Required Action End States for 
BWR Plants'' (Reference 1), into the BWR STS (Note: The changes are 
made with respect to Revision 2 of the STS NUREGs).
    TSTF-423 is one of the industry's initiatives developed under the 
Risk Management Technical Specifications (RMTS) program. These 
initiatives are intended to maintain or improve safety through the 
incorporation of risk assessment and management techniques in TS, while 
reducing unnecessary burden and making TS requirements consistent with 
the Commission's other risk-informed regulatory requirements, in 
particular the maintenance rule.
    The Code of Federal Regulations, 10 CFR 50.36, ``Technical 
Specifications,'' states: ``When a limiting condition for operation of 
a nuclear reactor is not met, the licensee shall shut down the reactor 
or follow the remedial action permitted by the technical specification 
until the condition can be met.'' The STS and many plant TS provide a 
completion time (CT) for the plant to meet the limiting condition for 
operation (LCO). If the LCO or the remedial action cannot be met, then 
the reactor is required to be shut down. When the STS and individual 
plant technical specifications were written, the shutdown condition or 
end state specified was usually cold shutdown.

[[Page 74039]]

    Topical Report NEDC-32988, Revision 2, provides the technical basis 
to change certain required end states when the TS Actions for remaining 
in power operation cannot be met within the CTs. Most of the requested 
TS changes permit an end state of hot shutdown (Mode 3), if risk is 
assessed and managed, rather than an end state of cold shutdown (Mode 
4) contained in the current TS. The request was limited to those end 
states where: (1) Entry into the shutdown mode is for a short interval, 
(2) entry is initiated by inoperability of a single train of equipment 
or a restriction on a plant operational parameter, unless otherwise 
stated in the applicable TS, and (3) the primary purpose is to correct 
the initiating condition and return to power operation as soon as is 
practical.
    The STS for BWR plants define five operational modes. In general, 
they are:
     Mode 1--Power Operation. The reactor mode switch is in run 
position.
     Mode 2--Reactor Startup. The reactor mode switch is in 
refuel position (with all reactor vessel head closure bolts fully 
tensioned) or in startup/hot standby position.
     Mode 3--Hot Shutdown. The reactor coolant system (RCS) 
temperature is above 200 degrees F (TS specific) and the reactor mode 
switch is in shutdown position (with all reactor vessel head closure 
bolts fully tensioned).
     Mode 4--Cold Shutdown. The RCS temperature is equal to or 
less than 200 degrees F and the reactor mode switch is in shutdown 
position (with all reactor vessel head closure bolts fully tensioned).
     Mode 5--Refueling. The reactor mode switch is in shutdown 
or refuel position, and one or more reactor vessel head closure bolts 
are less than fully tensioned.
    Criticality is not allowed in Modes 3 through 5.
    TSTF-423 generally allows a Mode 3 end state rather than a Mode 4 
end state for selected initiating conditions in order to perform short-
duration repairs which necessitate exiting the original Mode of 
operation. Short duration repairs are on the order of 2- to 3-days, but 
not more than a week.

2.0 Regulatory Evaluation

    In 10 CFR 50.36, the Commission established its regulatory 
requirements related to the content of TS. Pursuant to 10 CFR 50.36(c), 
TS are required to include items in the following five specific 
categories related to station operation: (1) Safety limits, limiting 
safety system settings, and limiting control settings; (2) limiting 
conditions for operation (LCOs); (3) surveillance requirements (SRs); 
(4) design features; and (5) administrative controls. The rule does not 
specify the particular requirements to be included in a plant's TS. As 
stated in 10 CFR 50.36(c)(2)(i), the ``Limiting conditions for 
operation are the lowest functional capability or performance levels of 
equipment required for safe operation of the facility. When a limiting 
condition for operation of a nuclear reactor is not met, the licensee 
shall shut down the reactor or follow any remedial action permitted by 
the technical specifications * * *.''
    Reference 1 states: ``Cold shutdown is normally required when an 
inoperable system or train cannot be restored to an operable status 
within the allowed time. Going to cold shutdown results in the loss of 
steam-driven systems, challenges the shutdown heat removal systems, and 
requires restarting the plant. A more preferred operational mode is one 
that maintains adequate risk levels while repairs are completed without 
causing unnecessary challenges to plant equipment during shutdown and 
startup transitions.'' In the end state changes under consideration 
here, a problem with a component or train has or will result in a 
failure to meet a TS, and a controlled shutdown has begun because a TS 
Action requirement cannot be met within the TS CT.
    Most of today's TS and the design basis analyses were developed 
under the perception that putting a plant in cold shutdown would result 
in the safest condition and the design basis analyses would bound 
credible shutdown accidents. In the late 1980s and early 1990s, the NRC 
and licensees recognized that this perception was incorrect and took 
corrective actions to improve shutdown operation. At the same time, 
standard TS were developed and many licensees improved their TS. Since 
enactment of a shutdown rule was expected, almost all TS changes 
involving power operation, including a revised end state requirement, 
were postponed (see, for example the Final Policy Statement on TS 
Improvements, Reference 2). However, in the mid 1990s, the Commission 
decided a shutdown rule was not necessary in light of industry 
improvements.
    Controlling shutdown risk encompasses control of conditions that 
can cause potential initiating events and responses to those initiating 
events that do occur. Initiating events are a function of equipment 
malfunctions and human error. Responses to events are a function of 
plant sensitivity, ongoing activities, human error, defense-in-depth, 
and additional equipment malfunctions.
    In practice, the risk during shutdown operations is often addressed 
via voluntary actions and application of 10 CFR 50.65 (Reference 3), 
the maintenance rule. Section 50.65(a)(4) states: ``Before performing 
maintenance activities * * * the licensee shall assess and manage the 
increase in risk that may result from the proposed maintenance 
activities. The scope of the assessment may be limited to structures, 
systems, and components that a risk-informed evaluation process has 
shown to be significant to public health and safety.'' Regulatory Guide 
(RG) 1.182 (Reference 4) provides guidance on implementing the 
provisions of 10 CFR 50.65(a)(4) by endorsing the revised Section 11 
(published separately) to NUMARC 93-01, Revision 2. The revised Section 
11 of NUMARC 93-01, Revision 2, was subsequently incorporated into 
Revision 3 of NUMARC 93-01 (Reference 5). However, Revision 3 has not 
yet been formally endorsed by the NRC. The changes in TSTF-423 are 
consistent with the rules, regulations and associated regulatory 
guidance, as noted above.

3.0 Technical Evaluation

    The changes proposed in TSTF-423 are consistent with the changes 
proposed and justified in Topical Report GE NEDC-32988-A, Revision 2, 
and approved by the associated NRC SE (Reference 6). The evaluation 
included in Reference 6, as appropriate and applicable to the changes 
of TSTF-423 (Reference 7), is reiterated here and differences from the 
SE are justified. In its application the licensee commits to TSTF-IG-
05-02, Implementation Guidance for TSTF-423, Revision 0, ``Technical 
Specifications End States, NEDC-32988-A,'' (Reference 8), which 
addresses a variety of issues such as considerations and compensatory 
actions for risk-significant plant configurations. An overview of the 
generic evaluation and associated risk assessment is provided below, 
along with a summary of the associated TS changes justified by 
Reference 1.

3.1 Risk Assessment

    The objective of the BWROG topical report (Reference 1) risk 
assessment was to show that any risk increases associated with the 
proposed changes in TS end states are either negligible or negative 
(i.e., a net decrease in risk).
    The BWROG topical report documents a risk-informed analysis of the 
proposed TS change. Probabilistic Risk Assessment (PRA) results and 
insights are used, in combination with results of deterministic 
assessments, to

[[Page 74040]]

identify and propose changes in ``end states'' for all BWR plants. This 
is in accordance with guidance provided in RG 1.174 (Reference 9) and 
RG 1.177 (Reference 10). The three-tiered approach documented in RG 
1.177, ``An Approach for Plant-Specific, Risk-Informed Decision Making: 
Technical Specifications,'' was followed. The first tier of the three-
tiered approach includes the assessment of the risk impact of the 
proposed change for comparison to acceptance guidelines consistent with 
the Commission's Safety Goal Policy Statement, as documented in RG 
1.174 entitled ``An Approach for Using Probabilistic Risk Assessment in 
Risk-Informed Decisions on Plant-Specific Changes to the Licensing 
Basis.'' In addition, the first tier aims at ensuring that there are no 
unacceptable temporary risk increases during the implementation of the 
proposed TS change, such as when equipment is taken out of service. The 
second tier addresses the need to preclude potentially high-risk 
configurations which could result if equipment is taken out of service 
concurrently with the implementation of the proposed TS change. The 
third tier addresses the application of 10 CFR 50.65(a)(4) of the 
Maintenance Rule for identifying risk-significant configurations 
resulting from maintenance related activities and taking appropriate 
compensatory measures to avoid such configurations. Unless invoked, 
such as by this or another TS application, 50.65(a)(4) is applicable to 
maintenance related activities and does not cover other operational 
activities beyond the effect they may have on existing maintenance 
related risk.
    BWROG's risk assessment approach was found comprehensive and 
acceptable in the SE for the topical report. In addition, the analyses 
show that the three-tiered approach criteria for allowing TS changes 
are met as follows:
     Risk Impact of the Proposed Change (Tier 1). The risk 
changes associated with the TS changes in TSTF-423, in terms of mean 
yearly increases in core damage frequency (CDF) and large early release 
frequency (LERF), are risk neutral or risk beneficial. In addition, 
there are no significant temporary risk increases, as defined by RG 
1.177 criteria, associated with the implementation of the TS end state 
changes.
     Avoidance of Risk-Significant Configurations (Tier 2). The 
performed risk analyses, which are based on single LCOs, shows that 
there are no high-risk configurations associated with the TS end state 
changes. The reliability of redundant trains is normally covered by a 
single LCO. When multiple LCOs occur, which affect trains in several 
systems, the plant's risk-informed configuration risk management 
program (CRMP), or the risk assessment and management program 
implemented in response to the Maintenance Rule 10 CFR 50.65(a)(4), 
shall ensure that high-risk configurations are avoided. As part of the 
implementation of TSTF-423, the licensee commits to follow Section 11 
of NUMARC 93-01, Revision 3, and include guidance in appropriate plant 
procedures and/or administrative controls to preclude high-risk plant 
configurations when the plant is at the proposed end state. The staff 
finds that such guidance is adequate for preventing risk-significant 
plant configurations.
     Configuration Risk Management (Tier 3). The licensee has a 
program in place to comply with 10 CFR 50.65 (a)(4) to assess and 
manage the risk from proposed maintenance activities. This program can 
support a licensee decision in selecting the appropriate actions to 
control risk for most cases in which a risk-informed TS is entered.
    The generic risk impact of the proposed end state mode change was 
evaluated subject to the following assumptions:
    1. The entry into the proposed end state is initiated by the 
inoperability of a single train of equipment or a restriction on a 
plant operational parameter, unless otherwise stated in the applicable 
technical specification.
    2. The primary purpose of entering the end state is to correct the 
initiating condition and return to power as soon as is practical.
    3. When Mode 3 is entered as the repair end state, the time the 
reactor coolant pressure is above 500 psig will be minimized. If 
reactor coolant pressure is above 500 psig for more than 12 hours, the 
associated plant risk will be assessed and managed.
    These assumptions are consistent with typical entries into Mode 3 
for short duration repairs, which is the intended use of the TS end 
state changes.
    The staff concludes that, in general, going to Mode 3 (hot 
shutdown) instead of going to Mode 4 (cold shutdown) to carry out 
equipment repairs that are of short duration, does not have any adverse 
effect on plant risk.

3.2 Assessment of TS Changes

    The changes proposed by the licensee and in TSTF-423 are consistent 
with the changes proposed in topical report GE NEDC-32988, Revision 2, 
and approved by the NRC SE of September 27, 2002. [NOTE: Only those 
changes proposed in TSTF-423 are addressed in this SE. The SE and 
associated topical report address the entire fleet of BWR plants, and 
the plants adopting TSTF-423 must confirm the applicability of the 
changes to their plant.] Following are the proposed changes, including 
a synopsis of the STS LCO, the change, and a brief conclusion of 
acceptability.
3.2.1 TS 4.5.1.2 and LCO 3.4.3 (BWR/4); TS 4.5.2.2 and LCO 3.4.4 (BWR/
6), Safety/Relief Valves (SRVs)
    The function of the SRVs is to protect the plant against severe 
overpressurization events. These TS provide the operability 
requirements for the SRVs as described below. The TS change allows the 
plant to remain in Mode 3 until the repairs are completed.

[Note: Plant Applicability, BWR4/6]

    LCO: The safety function of 11 SRVs must be operable (BWR/4 
plants). The safety function of seven SRVs must be operable and the 
relief function of seven additional SRVs must be operable (BWR/6 
plants).
    Condition requiring entry into end state: If the LCO cannot be met 
with one or two SRVs inoperable, the inoperable valves must be returned 
to operability within 14 days. If the SRVs cannot be returned to 
operable status within that time, the plant must be placed in Mode 3 
within 12 hours and in Mode 4 within 36 hours.
    Proposed modification for end state required actions: If the LCO 
cannot be met with one or two SRVs inoperable, the inoperable valves 
must be returned to operability within 14 days. If the one or two 
inoperable SRVs cannot be returned to operable status within 14 days, 
the plant must be placed in Mode 3 within 12 hours. If three or more 
SRVs become inoperable, the plant must be placed in Mode 4 within 36 
hours.
    Assessment: The BWROG topical report did a comparative PRA 
evaluation of the core damage risks of operation in the current end 
state and in the proposed Mode 3 end state. The evaluation indicates 
that the core damage risks are lower in Mode 3 than in Mode 4. Going to 
Mode 4 for one inoperable SRV would cause loss of the high-pressure 
steam-driven injection system (reactor core isolation cooling (RCIC)/
high pressure coolant injection (HPCI)), and loss of the power 
conversion system (condenser/feedwater), and require activating the 
residual heat removal (RHR) system. In addition, emergency operating 
procedures (EOPs) direct the operator to take control of the 
depressurization function if low pressure injection/spray

[[Page 74041]]

systems are needed for reactor pressure vessel (RPV) water makeup and 
cooling. Based on the low probability of loss of the necessary 
overpressure protection function and the number of systems available in 
Mode 3, the staff concludes in the SE (reference 6) for the BWROG 
topical report that the risks of staying in Mode 3 are approximately 
the same as, and in some cases lower than, the risks of going to the 
Mode 4 end state. The change allows the inoperable SRV to be repaired 
in a plant operating mode with lower risks. After repairs are made, the 
plant can be brought to full-power operation with less potential for 
transients and errors. The plant is taken into cold shutdown only when 
three or more SRVs are inoperable. Since the time spent in Mode 3 to 
perform the repair is infrequent and limited, the proposed change is 
acceptable, particularly in light of defense-in-depth considerations.
    Finding: Based on the above assessment, the staff finds that the 
requested change to allow operation in Mode 3 with a minimum number of 
SRVs inoperable after plant risk has been assessed and managed, is 
acceptable.
3.2.2 TS 4.5.1.3 and LCO 3.5.1 (BWR/4); TS 4.5.2.3 and LCO 3.5.1 (BWR/
6), Emergency Core Cooling Systems (ECCS) (Operating)
    The ECCS systems provide cooling water to the core in the event of 
a loss-of-coolant accident (LOCA). This set of ECCS TS provide the 
operability requirements for the various ECCS subsystems as described 
below. This TS change would delete the secondary actions. The plant can 
remain in Mode 3 until the required repair actions are completed. The 
reactor is not depressurized.

[Note: Plant Applicability, BWR4/6]

    LCO: Each ECCS injection/spray subsystem and the automatic 
depressurization system (ADS) function of seven BWR/4, or eight BWR/6, 
SRVs must be operable.
    Conditions requiring entry into end state: If the LCO cannot be 
met, the following actions must be taken for the listed conditions:
    a. If one low-pressure ECCS injection/spray subsystem is 
inoperable, the subsystem must be restored to operable status in 7 
days.
    b. If the inoperable ECCS injection/core spray cannot be restored 
to operable status, the plant must be placed in Mode 3 within 12 hours 
and Mode 4 within 36 hours (BWR/4 plants only).
    c. If two ECCS injection subsystems are inoperable or one ECCS 
injection subsystem and one ECCS spray system are inoperable, one ECCS 
injection/spray subsystem must be restored to operable status within 72 
hours. If this required action cannot be met, the plant must be placed 
in Mode 3 within 12 hours and in Mode 4 within 36 hours (BWR/6 plants 
only).
    d. If the HPCI/High Pressure Core Spray (HPCS) system is 
inoperable, the RCIC system must be verified to be operable by 
administrative means within 1 hour and the HPCI/HPCS system restored to 
operable status within 14 days.
    e. If one ADS valve is inoperable, it must be restored to operable 
status within 14 days.
    f. If one ADS valve is inoperable and one low-pressure ECCS 
injection/spray subsystem is inoperable, the ADS valve must be restored 
to operable status within 72 hours or the low-pressure ECCS injection/
spray subsystem must be restored to operable status within 72 hours.
    g. If two or more ADS valves become inoperable, or the required 
actions described in items e and/or f cannot be met, the plant must be 
placed in Mode 3 within 12 hours and the reactor steam dome pressure 
reduced to less than 150 psig within 36 hours.
    Proposed modification for end state required actions:
    a. No change
    b. If the ECCS injection or spray system is inoperable, the plant 
must be restored to operable status within 12 hours. The plant is not 
taken into Mode 4 (cold shutdown).
    c. If two ECCS injection subsystems are inoperable or one ECCS 
injection subsystem and one ECCS spray system are inoperable, one ECCS 
injection/spray subsystem must be restored to operable status within 72 
hours. If this required action cannot be met, the plant must be placed 
in Mode 3 within 12 hours. The plant is not taken into Mode 4 (BWR/6 
plants only).
    d. No change
    e. No change
    f. No change
    g. If two or more ADS valves become inoperable or the required 
actions described in item e and/or f cannot be met, the plant must be 
placed in Mode 3 within 12 hours. The reactor is not depressurized and 
not taken to Mode 4.
    Assessment: The BWROG topical report did a comparative PRA 
evaluation of the core damage risks of operation in the current end 
state and the proposed Mode 3 end state. The evaluation indicates that 
the core damage risks are lower in Mode 3 than in the current end state 
Mode 4. Going to Mode 4 for one ECCS subsystem or one ADS valve would 
cause loss of the high-pressure steam-driven injection system (RCIC/
HPCI), and loss of the power conversion system (condenser/feedwater), 
and require activating the RHR system. In addition, Plant Emergency 
Operating Procedures (EOPs) direct the operator to take control of the 
depressurization function if low-pressure injection/spray systems are 
needed for RPV water makeup and cooling. Based on the low probability 
of loss of the reactor coolant inventory and the number of systems 
available in Mode 3, the staff concludes in the SE to the BWR topical 
report that the risks of staying in Mode 3 are approximately the same 
as, and in some cases lower than, the risks of going to the Mode 4 end 
state.
    Finding: Based on the above assessment, and because the time spent 
in Mode 3 to perform the repair is infrequent and limited, and in light 
of defense-in-depth considerations, the proposed change is acceptable.
3.2.3 TS 4.5.1.4 and LCO 3.5.3 (BWR/4 only), Reactor Core Isolation 
Cooling (RCIC) System
    The function of the RCIC system is to provide reactor coolant 
makeup during loss of feedwater and other transient events. This TS 
provides the operability requirements for the RCIC system as described 
below. The TS change allows the plant to remain in Mode 3 until the 
repairs are completed.

[Note: Plant Applicability, BWR/4]

    LCO: The RCIC system must be operable during Modes 1, 2 and 3 when 
the reactor steam dome pressure is greater than 150 psig.
    Condition requiring entry into end state: If the LCO cannot be met, 
the following actions must be taken: (a) verify by administrative means 
within 1 hour that the HPCI system is operable, (b) restore the RCIC 
system to operable status within 14 days. If either or both actions 
cannot be completed within the allotted time, the plant must be placed 
in Mode 3 within 12 hours and the reactor steam dome pressure reduced 
to less than 150 psig within 36 hours.
    Proposed modification for end state required actions: This TS 
change keeps the plant in Mode 3 (hot shutdown) until the required 
repairs are completed. The reactor steam dome pressure is not reduced 
to less than 150 psig.
    Assessment: This change would allow the inoperable RCIC system to 
be repaired in a plant operating mode with lower risk and without 
challenging the normal shutdown systems. The BWROG

[[Page 74042]]

topical report did a comparative PRA evaluation of the core damage 
risks of operation in the current end state and in the proposed Mode 3 
end state. The evaluation indicates that the core damage risks are 
lower in Mode 3 than in Mode 4. Going to Mode 3 with reactor steam dome 
pressure less than 150 psig for inoperability of RCIC would also cause 
loss of the high-pressure steam-driven injection system HPCI and loss 
of the power conversion system (condenser/ feedwater), and would 
require activating the RHR system. In addition, Plant EOPs direct the 
operator to take control of the depressurization function if low 
pressure injection/spray systems are needed for RPV water makeup and 
cooling. Based on the low probability of loss of the necessary 
overpressure protection function and the number of systems available in 
Mode 3, the staff concludes in the SE to the BWR topical report that 
the risks of staying in Mode 3 are approximately the same as, and in 
some cases lower than, the risks of going to the Mode 4 end state.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations, the proposed change is 
acceptable.
3.2.4 TS 4.5.1.6 and LCO 3.6.1.6 (BWR/4); TS 5.5.2.5 and LCO 3.6.1.6 
(BWR/6), Low-Low Set Logic (LLS) Valves
    The function of LLS logic is to prevent excessive short-duration 
SRV cycling during an overpressure event. This TS provides operability 
requirements for the four LLS SRVs as described below. The TS change 
allows the plant to remain in Mode 3 until the repairs are completed.

[Note: Plant Applicability, BWR 4/6]

    Conditions requiring entry into end state: If one LLS valve is 
inoperable, it must be returned to operability within 14 days. If the 
LLS valve cannot be returned to operable status within the allotted 
time, the plant must be placed in Mode 3 within 12 hours and in Mode 4 
within 36 hours.
    Proposed modification for end state required actions: The TS change 
would keep the plant in Mode 3 until the required repair actions are 
completed. The plant would not be taken into Mode 4 (cold shutdown).
    Assessment: The BWROG topical report did a comparative PRA 
evaluation of the core damage risks of operation in the current end 
state and the proposed Mode 3 end state. The evaluation indicates that 
the core damage risks are lower in Mode 3 than in Mode 4, the current 
end state. Going to Mode 4 for one LLS inoperable SRV would cause loss 
of the high-pressure steam-driven injection system (RCIC/HPCI), and 
loss of the power conversion system (condenser/feedwater), and would 
require activating the RHR system. With one LLS valve inoperable, the 
remaining valves are adequate to perform the required function. EOPs 
direct the operator to take control of the depressurization function if 
low pressure injection/spray systems are needed for RPV water makeup 
and cooling. Based on the low probability of loss of the necessary 
overpressure protection function during the infrequent and limited time 
in Mode 3 and the number of systems available in Mode 3, the staff 
concludes in the SE to the BWR topical report that the risks of staying 
in Mode 3 are approximately the same as and in some cases lower than 
the risks of going to the Mode 4 end state. The proposed change allows 
repairs of the inoperable SRV to be performed in a plant operating mode 
with lower risks.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations, the proposed change is 
acceptable.
3.2.5 TS 4.5.1.1, TS 4.5.2.1 and LCO 3.3.8.2, Reactor Protection System 
(RPS) Electric Power Monitoring
    RPS Electric Power Monitoring System is provided to isolate the RPS 
bus from the motor generator (MG) set or an alternate power supply in 
the event of over voltage, under voltage, or under frequency. This 
system protects the load connected to the RPS bus against unacceptable 
voltage and frequency conditions and forms an important part of the 
primary success path of the essential safety circuits. Some of the 
essential equipment powered from the RPS buses includes the RPS logic, 
scram solenoids, and various valve isolation logic. The TS change 
allows the plant to remain in Mode 3 until the repairs are completed.

[Note: Plant Applicability, BWR 4/6]

    LCO: For Modes 1, 2, 3 and Modes 4 and 5 (with any control rod 
withdrawn from a core cell containing one or more fuel assemblies), two 
RPS electric power monitoring assemblies shall be operable for each in-
service RPS motor generator set or alternate power supply.
    Condition Requiring Entry into End State: If the LCO cannot be met, 
the associated in-service power supply(s) must be removed from service 
within 72 hours for one Electric Power Assembly (EPA) inoperable or 
within one hour for both EPAs inoperable. In Modes 1, 2, and 3, if the 
in-service power supply(s) cannot be removed from service within the 
allotted time, the plant must be placed in Mode 3 within 12 hours and 
Mode 4 within 36 hours.
    Proposed Modification: The proposed change is to keep the plant in 
Mode 3 until the repair actions are completed. Delete required action 
in C.2 which required the plant to be in Mode 4.
    Assessment: To reach Mode 3 per the TS, there must be a functioning 
power supply with degraded protective circuitry in operation. However, 
the over voltage, under voltage, or under frequency condition must 
exist for an extended time period to cause damage. There is a low 
probability of this occurring in the short period of time that the 
plant would remain in Mode 3 without this protection.
    The specific failure condition of interest is not risk significant 
for BWR PRAs. If the required restoration actions cannot be completed 
within the specified time, going into Mode 4 would cause loss of the 
high-pressure steam-driven injection system (RCIC/HPCI) and loss of the 
power conversion system (condenser/feedwater), and would require 
activating the RHR system. In addition, EOPs direct the operator to 
take control of the depressurization function if low pressure 
injection/spray systems are needed for RPV water makeup and cooling. 
Based on the low probability of loss of the RPS power monitoring system 
during the infrequent and limited time in Mode 3 and the number of 
systems available in Mode 3, the staff concludes in the SE to the BWR 
topical report that the risks of staying in Mode 3 are approximately 
the same as and in some cases lower than the risks of going to the Mode 
4 end state.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations, the proposed change is 
acceptable.
3.2.6 TS 4.5.1.19 and LCO 3.8.1(BWR/4); TS 4.5.2.17 and LCO 3.8.1(BWR/
6), AC Sources (Operating)
    The purpose of the AC electrical system is to provide during all 
situations the power required to put and maintain the plant in a safe 
condition and prevent the release of radioactivity to the environment.
    The Class 1E electrical power distribution system AC sources 
consist of the offsite power source (preferred power sources, normal 
and alternate(s)), and the onsite standby power sources

[[Page 74043]]

(e.g., emergency diesel generators (EDGs)). In addition, many sites 
provide a crosstie capability between units.
    As required by General Design Criterion (GDC) 17 of 10 CFR Part 50, 
Appendix A, the design of the AC electrical system provides 
independence and redundancy. The onsite Class 1E AC distribution system 
is divided into redundant divisions so that the loss of any one 
division does not prevent the minimum safety functions from being 
performed. Each division has connections to two preferred offsite power 
sources and a single EDG or other Class 1E Standby AC power source.
    Offsite power is supplied to the unit switchyard(s) from the 
transmission network by two transmission lines. From the switchyard(s), 
two electrically and physically separated circuits provide AC power 
through a stepdown transformer(s) to the 4.16-kV emergency buses.
    In the event of a loss of offsite power, the emergency electrical 
loads are automatically connected to the EDGs in sufficient time to 
provide for a safe reactor shutdown and to mitigate the consequence of 
a design basis accident (DBA) such as a LOCA.

[Note: Plant Applicability, BWR 4/6]

    LCO: The following AC electrical power sources shall be operable in 
Modes 1, 2, and 3:
    a. Two qualified circuits between the offsite transmission network 
and the onsite Class1E AC Electric Power Distribution System,
    b. Three EDGs,
    c. Automatic Load Sequencers.
    Condition requiring entry into end state: Plant operators must 
bring the plant to Mode 4 within 36 hours following the sustained 
inoperability of one required Automatic Load Sequencer; either or both 
required offsite circuits; either one, two or three required EDGs; or 
one required offsite circuit and one, two or three required EDGs.
    Proposed modification for end state require actions: Delete 
required action G.2 to go to Mode 4 (cold shutdown). The plant will 
remain in Mode 3 (hot shutdown).
    Assessment: Entry into any of the conditions for the AC power 
sources implies that the AC power sources have been degraded and the 
single failure protection for the safe shutdown equipment may be 
ineffective. Consequently, as specified in TS 3.8.1 at present, the 
plant operators must bring the plant to Mode 4 when the required action 
is not completed by the specified time for the associated action.
    The BWROG topical report did a comparative PRA evaluation of the 
core damage risks of operation in the current end state and in the 
proposed Mode 3 end state. Events initiated by the loss of offsite 
power are dominant contributors to core damage frequency in most BWR 
PRAs, and the steam-driven core cooling systems, RCIC and HPCI, play a 
major role in mitigating these events. The evaluation indicates that 
the core damage risks are lower in Mode 3 than in Mode 4 for one 
inoperable AC power source. Going to Mode 4 for one inoperable AC power 
source would cause loss of the high-pressure steam-driven injection 
system (RCIC/HPCI), and loss of the power conversion system (condenser/
feedwater), and require activating the RHR system. In addition, EOPs 
direct the operator to take control of the depressurization function if 
low pressure injection/spray systems are needed for RPV water makeup 
and cooling. Based on the low probability of loss of the AC power and 
the number of steam-driven systems available in Mode 3, the staff 
concludes in the SE to the BWR topical report that the risks of staying 
in Mode 3 are lower than going to the Mode 4 end state.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations, the proposed change is 
acceptable.
3.2.7 TS 4.5.1.20 and LCO 3.8.4 (BWR/4); TS 4.5.2.18 and LCO 3.8.4 DC 
Sources (Operating)
    The purpose of the DC power system is to provide a reliable source 
of DC power for both normal and abnormal conditions. It must supply 
power in an emergency for an adequate length of time until normal 
supplies can be restored.
    The DC electrical system:
    a. Provides the AC emergency power system with control power,
    b. Provides motive and control power to selected safety related 
equipment, and
    c. Provides power to preferred AC vital buses (via inverters).

[Note: Plant Applicability, BWR 4/6]

    LCO: For Modes 1, 2 and 3, the following DC sources are required to 
be operable:
    BWR/4: The (Division 1 and Division 2 station service, and DG 1B, 
2A, and 2C) DC electrical power systems shall be operable.
    BWR/6: The (Divisions 1, 2, and 3) DC electrical power subsystems 
shall be operable.
    Condition requiring entry into end state: The plant operators must 
bring the plant to Mode 3 within 12 hours and Mode 4 within 36 hours 
following the sustained inoperability of one DC electrical power 
subsystem for a period of 2 hours.
    Proposed modification for end state required actions: The proposed 
TS change is to remove the requirement to place the plant in Mode 4, 
Required Actions in D.2 (BWR/4) and E.2 (BWR/6) are deleted.
    Assessment: If one of the DC electrical power subsystems is 
inoperable, the remaining DC electrical power subsystems have the 
capacity to support a safe shutdown and to mitigate an accident 
condition. The BWROG topical report did a comparative PRA evaluation of 
the core damage risks of operation in the current end state and in the 
proposed Mode 3 end state, with one DC system inoperable. Events 
initiated by the loss of offsite power are dominant contributors to 
core damage frequency in most BWR PRAs, and the steam-driven core 
cooling systems, RCIC and HPCI, play a major role in mitigating these 
events. The evaluation indicates that the core damage risks are lower 
in Mode 3 than in Mode 4. Going to Mode 4 for one inoperable DC power 
source would cause loss of the high-pressure steam-driven injection 
system (RCIC/HPCI), and loss of the power conversion system (condenser/
feedwater), and require activating the RHR system. In addition, EOPs 
direct the operator to take control of the depressurization function if 
low pressure injection/spray systems are needed for RPV water makeup 
and cooling. Based on the low probability of loss of the DC power and 
the number of systems available in Mode 3, the staff concludes in the 
SE to the BWR topical report that the risks of staying in Mode 3 are 
approximately the same as and in some cases lower than the risks of 
going to the Mode 4 end state.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations, the proposed change is 
acceptable.
3.2.8 TS 4.5.1.21 and LCO 3.8.7 (BWR/4); TS 4.5.2.19 and 3.8.7 (BWR/6), 
Inverters (Operating)
    In Modes 1, 2, and 3, the inverters provide the preferred source of 
power for the 120-VAC vital buses which power the reactor protection 
system (RPS) and the Emergency Core Cooling Systems (ECCS) initiation. 
The inverter can be powered from an internal AC

[[Page 74044]]

source/rectifier or from the station battery.

[Note: Plant Applicability, BWR 4/6]

    LCO: For Modes 1, 2, and 3 the following Inverters shall be 
operable:
    BWR/4: The (Division 1 and Division 2) shall be operable.
    BWR/6: The (Divisions 1, 2, and 3) shall be operable.
    Condition requiring entry into end state: The plant operators must 
bring the plant to Mode 3 within 12 hours and Mode 4 within 36 hours 
following the sustained inoperability of the required inverter for a 
period of 24 hours.
    Proposed modification for end state required actions: The proposed 
TS change is to remove the requirement to place the plant in Mode 4. 
Required Actions in B.2 (BWR/4) and C.2 (BWR/6) are deleted.
    Assessment: If one of the Inverters is inoperable, the remaining 
Inverters have the capacity to support a safe shutdown and to mitigate 
an accident condition. The BWROG topical report did a comparative PRA 
evaluation of the core damage risks of operation in the current end 
state and in the proposed Mode 3 end state, with an inoperable 
Inverter. Events initiated by the loss of offsite power are dominant 
contributors to core damage frequency in most BWR PRAs, and the steam-
driven core cooling systems, RCIC and HPCI, play a major role in 
mitigating these events. The evaluation indicates that the core damage 
risks are lower in Mode 3 than in Mode 4. Going to Mode 4 for one 
inoperable Inverter power source would cause loss of the high-pressure 
steam-driven injection system (RCIC/HPCI), and loss of the power 
conversion system (condenser/feedwater), and require activating the RHR 
system. In addition, EOPs direct the operator to take control of the 
depressurization function if low pressure injection/spray systems are 
needed for RPV water makeup and cooling. Based on the low probability 
of loss of the Inverters during the infrequent and limited time in Mode 
3 and the number of systems available in Mode 3, the staff concludes in 
the SE to the BWR topical report that the risks of staying in Mode 3 
are approximately the same as and in some cases lower than the risks of 
going to the Mode 4 end state.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations, the proposed change is 
acceptable.
3.2.9 TS 4.5.1.22 and LCO 3.8.9 (BWR/4); TS 4.5.2.20 and LCO 3.8.9 
(BWR/6), Distribution Systems (Operating)
    The onsite Class 1E AC and DC electrical power distribution system 
is divided into redundant and independent AC, DC, and AC vital bus 
electrical power distribution systems. The primary AC electrical power 
distribution subsystem for each division consists of a 4.16-kV 
Engineered Safety Feature (ESF) bus having an offsite source of power 
as well as a dedicated onsite EDG source. The secondary plant 
distribution subsystems include 600-VAC emergency buses and associated 
load centers, motor control centers, distribution panels and 
transformers. The 120-VAC vital buses are arranged in four load groups 
and normally powered from DC via the inverters. There are two 
independent 125/250-VDC station service electrical power distribution 
systems and three independent 125-VDC DG electrical power distribution 
subsystems that support the necessary power for ESF functions. Each 
subsystem consists of a 125-VDC and 250-VDC bus and associated 
distribution panels.

[Note: Plant Applicability, BWR 4/6]

    LCO: For Modes 1, 2, and 3, the following electrical power 
distribution subsystems shall be operable:
    BWR/4: The Division 1 and Division 2 AC, DC, and AC vital buses 
shall be operable.
    BWR/6: The Divisions 1, 2, and 3 AC, DC, and AC vital buses shall 
be operable.
    Condition requiring entry into end state: The plant operators must 
bring the plant to Mode 3 within 12 hours and Mode 4 within 36 hours 
following the sustained inoperability of one AC or one DC or one AC 
vital bus electrical power subsystem for a period of 8 hours, 2 hours 
and 2 hours, respectively (with a maximum 16 hour Completion Time limit 
from initial discovery of failure to meet the LCO, to preclude being in 
the LCO indefinitely).
    Proposed modification for end state required actions: The proposed 
TS change is to remove the requirement to place the plant in Mode 4, 
Required Action in D.2 (BWR/4) and D.2 (BWR/6) are deleted.
    Assessment: If one of the AC/DC/AC vital subsystems is inoperable, 
the remaining AC/DC/AC vital subsystems have the capacity to support a 
safe shutdown and to mitigate an accident condition. The BWROG topical 
report did a comparative PRA evaluation of the core damage risks of 
operation in the current end state and in the proposed Mode 3 end 
state, with one of the AC/DC/AC vital subsystems inoperable. Events 
initiated by the loss of offsite power are dominant contributors to 
core damage frequency in most BWR PRAs, and the steam-driven core 
cooling systems, RCIC and HPCI, play a major role in mitigating these 
events. The evaluation indicates that the core damage risks are lower 
in Mode 3 than in Mode 4. Going to Mode 4 for one inoperable AC/DC/AC 
vital subsystem would cause loss of the high-pressure steam-driven 
injection system (RCIC/HPCI), and loss of the power conversion system 
(condenser/feedwater), and require activating the RHR system. In 
addition, EOPs direct the operator to take control of the 
depressurization function if low pressure injection/spray systems are 
needed for RPV water makeup and cooling. Based on the low probability 
of loss of the AC/DC/AC vital electrical subsystems during the 
infrequent and limited time in Mode 3 and the number of systems 
available in Mode 3, the staff concludes in the SE to the BWR topical 
report that the risks of staying in Mode 3 are approximately the same 
as and in some cases lower than the risks of going to the Mode 4 end 
state.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations, the proposed change is 
acceptable.
3.2.10 TS 4.5.1.5 and LCO 3.6.1.1, Primary Containment
    The function of the primary containment is to isolate and contain 
fission products released from the Reactor Primary System following a 
design basis LOCA and to confine the postulated release of 
radioactivity. The primary containment consists of a steel-lined, 
reinforced concrete vessel, which surrounds the Reactor Primary System 
and provides an essentially leak-tight barrier against an uncontrolled 
release of radioactivity to the environment. Additionally, this 
structure provides shielding from the fission products that may be 
present in the primary containment atmosphere following accident 
conditions.

[Note: Plant Applicability, BWR 4/6]

    LCO: The primary containment shall be operable.
    Condition Requiring Entry into End State: If the LCO cannot be met, 
the primary containment must be returned to operability within one hour 
(Required Action A.1). If the primary containment cannot be returned to 
operable status within the allotted time, the plant must be placed in 
Mode 3 within 12 hours

[[Page 74045]]

(Required Action B.1) and in Mode 4 within 36 hours (Required Action 
B.2).
    Proposed Modification for End State Required Actions: Delete 
Required Action B.2.
    Assessment: The primary containment is one of the three primary 
boundaries to the release of radioactivity. (The other two are the fuel 
cladding and the Reactor Primary System pressure boundary.) Compliance 
with this LCO ensures that a primary containment configuration exists, 
including equipment hatches and penetrations, that is structurally 
sound and will limit leakage to those leakage rates assumed in the 
safety analyses. This LCO entry condition does not include leakage 
through an unisolated release path. The BWROG topical report has 
determined that previous generic PRA work related to Appendix J 
requirements has shown that containment leakage is not risk 
significant. Should a fission product release from the primary 
containment occur, the secondary containment and related functions 
would remain operable to contain the release, and the standby gas 
treatment system would remain available to filter fission products from 
being released to the environment. By remaining in Mode 3, HPCI, RCIC, 
and the power conversion system (condensate/feedwater) remain available 
for water makeup and decay heat removal. Additionally, the EOPs direct 
the operators to take control of the depressurization function if low 
pressure injection/spray are needed for reactor coolant makeup and 
cooling. Therefore, defense-in-depth is maintained with respect to 
water makeup and decay heat removal by remaining in Mode 3.
    Finding: The requested change is acceptable. Note that the staff's 
approval relies upon the secondary containment and the standby gas 
treatment system for maintaining defense-in-depth while in this reduced 
end state.
3.2.11 TS 4.5.1.7 and LCO 3.6.1.7, Reactor Building-to-Suppression 
Chamber Vacuum Breakers (BWR/4 only)
    The reactor building-to-suppression chamber vacuum breakers relieve 
vacuum when the primary containment depressurizes below the pressure of 
the reactor building, thereby serving to preserve the integrity of the 
primary containment.

[Note: Plant Applicability, BWR/4]

    LCO: Each reactor building-to-suppression chamber vacuum breaker 
shall be operable.
    Condition Requiring Entry into End State: If one line has one or 
more reactor building-to-suppression chamber vacuum breakers inoperable 
for opening, the breaker(s) must be returned to operability within 72 
hours (Required Action C.1). If the vacuum breaker(s) cannot be 
returned to operability within the allotted time, the plant must be 
placed in Mode 3 within 12 hours (Required Action E.1) and in Mode 4 
within 36 hours (Required Action E.2).
    Proposed Modification for End State Required Actions: Modify the 
Required Actions so that if vacuum breaker(s) cannot be returned to 
operable status within the required Completion Times, the plant is 
placed in hot shutdown. That is, modify Condition E to relate only to 
Condition C, delete Required Action E.2, and add Condition F, with 
Required Actions F.1 and F.2, shutting down the plant to Mode 3 and 
then Mode 4 respectively, to address an inability to comply with the 
required actions related to the other Conditions (i.e., Conditions A, 
B, and D).
    Assessment: The BWROG topical report has determined that the 
specific failure condition of interest is not risk significant in BWR 
PRAs. The reduced end state would only be applicable to the situation 
where the vacuum breaker(s) in one line are inoperable for opening, 
with the remaining operable vacuum breakers capable of providing the 
necessary vacuum relief function. The existing end state remains 
unchanged, as established by new Condition F, for conditions involving 
more than one inoperable line or vacuum breaker since they are needed 
in Modes 1, 2, and 3. In Mode 3, for other accident considerations, 
HPCI, RCIC, and the power conversion system (condensate/feedwater) 
remain available for water makeup and decay heat removal. Additionally, 
the EOPs direct the operators to take control of the depressurization 
function if low pressure injection/spray are needed for reactor coolant 
makeup and cooling. Therefore, defense-in-depth is maintained with 
respect to water makeup and decay heat removal by remaining in Mode 3.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations, the proposed change is 
acceptable.
3.2.12 TS 4.5.1.8 and LCO 3.6.1.8, Suppression Chamber-to-Drywell 
Vacuum Breakers (BWR/4 only)
    The function of the suppression chamber-to-drywell vacuum breakers 
is to relieve vacuum in the drywell, thereby preventing an excessive 
negative differential pressure across the wetwell/drywell boundary.

[Note: Plant Applicability, BWR/4]

    LCO: Nine suppression chamber-to-drywell vacuum breakers shall be 
operable for opening.
    Condition Requiring Entry into End State: If one suppression 
chamber-to-drywell vacuum breaker is inoperable for opening, the 
breaker must be returned to operability within 72 hours (Required 
Action A.1). If the vacuum breaker cannot be returned to operability 
within the allotted time, the plant must be placed in Mode 3 within 12 
hours (Required Action C.1) and in Mode 4 within 36 hours (Required 
Action C.2).
    Proposed Modification for End State Required Actions: Modify the 
Required Actions so that if vacuum breaker(s) cannot be returned to 
operable status within the required Completion Times, the plant is 
placed in hot shutdown. That is, modify Condition C to relate only to 
Condition A, and delete Required Action C.2, and add Condition D, with 
Required Actions D.1 and D.2, shutting down the plant to Mode 3 and 
then Mode 4 respectively, to address an inability to comply with the 
required actions related to Condition B, to close the vacuum breaker.
    Assessment: The BWROG topical report has determined that the 
specific failure of interest is not risk significant in BWR PRAs. The 
reduced end state would only be applicable to the situation where one 
suppression chamber-to-drywell vacuum breaker is inoperable for 
opening, with the remaining operable vacuum breakers capable of 
providing the necessary vacuum relief function, since they are required 
in Modes 1, 2, and 3. By remaining in Mode 3, HPCI, RCIC, and the power 
conversion system (condensate/feedwater) remain available for water 
makeup and decay heat removal. Additionally, the EOPs direct the 
operators to take control of the depressurization function if low 
pressure injection/spray are needed for RCS makeup and cooling. 
Therefore, defense-in-depth is maintained with respect to water makeup 
and decay heat removal by remaining in Mode 3. The existing end state 
remains unchanged for conditions involving any suppression chamber-to-
drywell vacuum breakers that are stuck open, as established by new 
Condition D.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of

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defense-in-depth considerations, the proposed change is acceptable.
3.2.13 TS 4.5.1.9, TS 4.5.2.8, and LCO 3.6.1.9, Main Steam Isolation 
Valve (MSIV) Leakage Control System (LCS)
    The MSIV LCS supplements the isolation function of the MSIVs by 
processing the fission products that could leak through the closed 
MSIVs after core damage, assuming leakage rate limits which are based 
on a large LOCA.

[Note: Plant Applicability, BWR 4/6]

    LCO: Two MSIV LCS subsystems shall be operable.
    Condition Requiring Entry Into End State: If one MSIV LCS subsystem 
is inoperable, it must be restored to operable status within 30 days 
(Required Action A.1). If both MSIV LCS subsystems are inoperable, one 
of the MSIV LCS subsystems must be restored to operable status within 
seven days (Required Action B.1). If the MSIV LCS subsystems cannot be 
restored to operable status within the allotted time, the plant must be 
placed in Mode 3 within 12 hours (Required Action C.1) and in Mode 4 
within 36 hours (Required Action C.2).
    Proposed Modification for End State Required Actions: Delete 
Required Action C.2.
    Assessment: The BWROG topical report has determined that this 
system is not significant in BWR PRAs and, based on a BWROG program, 
many plants have eliminated the system altogether. The unavailability 
of one or both MSIV LCS subsystems has no impact on CDF or LERF, 
irrespective of the mode of operation at the time of the accident. 
Furthermore, the challenge frequency of the MSIV LCS system (i.e., the 
frequency with which the system is expected to be challenged to 
mitigate offsite radiation releases resulting from MSIV leaks above TS 
limits) is less than 1.0E-6/yr. Consequently, the conditional 
probability that this system will be challenged during the repair time 
interval while the plant is at either the current or the proposed end 
state (i.e., Mode 4 or Mode 3, respectively) is less than 1.0E-8. This 
probability is considerably smaller than probabilities considered 
``negligible'' in Regulatory Guide 1.177 for much higher consequence 
risks, such as large early release.
    Section 6 of reference 6 summarizes the staff's risk argument for 
approval of TSs 4.5.1.9, 4.5.2.8, and LCO 3.6.1.9, ``Main Steam 
Isolation Valve (MSIV) Leakage Control System (LCS).'' The argument for 
staying in Mode 3 instead of going to Mode 4 to repair the MSIV LCS 
system (one or both trains) is also supported by defense-in-depth 
considerations. Section 6.2 makes a comparison between the current 
(Mode 3) and the proposed (Mode 4) end state, with respect to the means 
available to perform critical functions (i.e., functions contributing 
to the defense-in-depth philosophy) whose success is needed to prevent 
core damage and containment failure and mitigate radiation releases. 
The risk and defense-in-depth arguments, used according to the 
``integrated decision-making'' process of Regulatory Guides 1.174 and 
1.177, support the conclusion that the plant in Mode 3 is as safe as 
Mode 4 (if not safer) for repairing an inoperable MSIV LCS system. 
Personnel safety must be considered separately.
    Finding: Based upon the above assessment, and because the time 
spent in Mode 3 to perform the repair is infrequent and limited, and in 
light of defense-in-depth considerations, the proposed change is 
acceptable.
3.2.14 TS 4.5.1.11 and LCO 3.6.2.4, Residual Heat Removal (RHR) 
Suppression Pool