Text

License Amendment Request to Relocate TS Surveillance Frequencies to Licensee Controlled Program in Accordance with TSTF-425, Revision 3
	ML14301A112
Person / Time
Site:	Millstone
Issue date:	10/22/2014
From:	Mark D. Sartain; Dominion, Dominion Nuclear Connecticut
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	14-434
	Download: ML14301A112 (176)
	v • d • e

Dominion Nuclear Connecticut, Inc.

5000 Dominion Boulevard, Glen Allen, VA 23060 Web Address: wwwv.dom.com October 22, 2014 U.S. Nuclear Regulatory Commission Serial No.14-434 Attention: Document Control Desk NSSL/MLC RO Washington, DC 20555 Docket No. 50-336 License No. DPR-65 DOMINION NUCLEAR CONNECTICUT, INC.

MILLSTONE POWER STATION UNIT 2 LICENSE AMENDMENT REQUEST TO RELOCATE TS SURVEILLANCE FREQUENCIES TO LICENSEE CONTROLLED PROGRAM IN ACCORDANCE WITH TSTF-425, REVISION 3 In accordance with the provisions of 10 CFR 50.90, Dominion Nuclear Connecticut, Inc. (DNC) is submitting a request for an amendment to the technical specifications (TS) for Millstone Power Station Unit 2 (MPS2). The proposed amendment would modify TSs by relocating specific surveillance frequencies to a licensee-controlled program with the adoption of Technical Specification Task Force (TSTF)-425, Revision 3, "Relocate Surveillance Frequencies to Licensee Control - Risk-Informed Technical Specification Task Force (RITSTF) Initiative 5b." Additionally, the change would add a new program, the Surveillance Frequency Control Program (SFCP), to TS Section 6, Administrative Controls. The changes are consistent with NRC-approved Industry/TSTF Standard Technical Specifications (STS) change TSTF-425, Revision 3, (ADAMS Accession No. ML090850642). The Federal Register notice published on July 6, 2009 (74 FR 31996), announced the availability of this TS improvement.

Attachment 1 provides a description and assessment of the proposed changes.

Attachment 2 includes DNC documentation with regard to Probabilistic Risk Assessment technical adequacy. Attachment 4 provides a cross-reference between the NUREG-1432 surveillances included in TSTF-425 versus the MPS2 surveillances included in this amendment request. Attachments 3 and 6 provide the MPS2 marked-up TS pages and TS Bases pages, respectively. The marked-up TS Bases pages are provided for information only. The changes to the affected TS Bases pages will be incorporated in accordance with the TS Bases Control Program upon approval of this amendment request.

As detailed in Attachment 5, the proposed amendment does not involve a Significant Hazards Consideration pursuant to the provisions of 10 CFR 50.92.

The Facility Safety Review Committee has reviewed and concurred with the determinations herein.

Issuance of this amendment is requested no later than October 22, 2015 with the amendment to be implemented within 90 days.

Serial No: 14-434 Docket No. 50-336 Adoption of TSTF-425, Rev. 3 Page 2 of 3 In accordance with 10 CFR 50.91(b), a copy of this license amendment request is being provided to the State of Connecticut.

Should you have any questions in regard to this submittal, please contact Wanda Craft at (804) 273-4687.

Sincerely, Mark D. Sartain -_________,-_____

Vice President - Nuclear Engineering I NOTARY PU*LIC I Commonwealth of Virginia Reg. # 140542 MyCommission Expires May 31, 2016 COMMONWEALTH OF VIRGINIA COUNTY OF HENRICO The foregoing document was acknowledged before me, in and for the County and Commonwealth aforesaid, today by Mark D. Sartain, who is Vice President - Nuclear Engineering of Dominion Nuclear Connecticut, Inc. He has affirmed before me that he is duly authorized to execute and file the foregoing document in behalf of that company, and that the statements in the document are true to the best of his knowledge and belief.

Acknowledged before me this ý Vday

-- of 2014.

My Commission Expires: A MK " 0/

Notary Public Attachments:

1. Description and Assessment of Proposed Changes

2. Documentation of PRA Technical Adequacy

3. Marked-up Technical Specifications Changes

4. Cross-References - NUREG-1432 to MPS2 TS Surveillance Frequencies Removed

5. Significant Hazards Consideration Determination

6. Marked-Up Technical Specifications Bases Changes (For Information Only)

Commitments made in this letter: None

Serial No: 14-434 Docket No. 50-336 Adoption of TSTF-425, Rev. 3 Page 3 of 3 cc: U.S. Nuclear Regulatory Commission Region I 2100 Renaissance Blvd Suite 100 King of Prussia, PA 19406-2713 M. C. Thadani Senior Project Manager U.S. Nuclear Regulatory Commission One White Flint North, Mail Stop 08-Bl 11555 Rockville Pike Rockville, MD 20852-2738 NRC Senior Resident Inspector Millstone Power Station Director, Radiation Division Department of Energy and Environmental Protection 79 Elm Street Hartford, CT 06106-5127

Serial No.14-434 Docket No. 50-336 ATTACHMENT I Description and Assessment of Proposed Changes DOMINION NUCLEAR CONNECTICUT, INC.

MILLSTONE POWER STATION UNIT 2

Serial No.14-434 Docket No. 50-336 Attachment 1, Page 1 of 5 DESCRIPTION AND ASSESSMENT OF PROPOSED CHANGES

1.0 DESCRIPTION

In accordance with the provisions of 10 CFR 50.90, Dominion Nuclear Connecticut, Inc.

(DNC) submits a request for an amendment to the technical specifications (TSs) for Millstone Power Station Unit 2 (MPS2). The proposed amendment would modify TSs by relocating specific surveillance frequencies to a licensee-controlled program with the adoption of Technical Specification Task Force (TSTF)-425, Revision 3, "Relocate Surveillance Frequencies to Licensee Control - Risk Informed Technical Specification Task Force (RITSTF) Initiative 5b." Additionally, the change would add a new program, the Surveillance Frequency Control Program (SFCP), to TS Section 6, Administrative Controls. The changes are consistent with NRC-approved Industry/TSTF Standard Technical Specifications (STS) change TSTF-425, Revision 3, (ADAMS Accession No. ML090850642). The Federal Register notice published on July 6, 2009 (74 FR 31996),

announced the availability of this TS improvement.

2.0 ASSESSMENT 2.1 Applicability of Published Safety Evaluation DNC has reviewed the safety evaluation provided in Federal Register Notice 74 FR 31996, dated July 6, 2009. This review included a review of the NRC staff's evaluation, TSTF-425, Revision 3, and the requirements specified in NEI 04-10, Rev. 1 (ADAMS Accession No. ML071360456). includes DNC documentation with regard to the technical adequacy of the probabilistic risk assessment (PRA) consistent with the requirements of Regulatory Guide (RG) 1.200, Revision 1 (ADAMS Accession No. ML070240001), Section 4.2. also describes the PRA models without NRC-endorsed standards, including documentation of the quality characteristics of those models in accordance with RG 1.200.

DNC has concluded that the justifications presented in the TSTF proposal and the safety evaluation prepared by the NRC staff are applicable to MPS2 and justify this amendment to incorporate the changes to the MPS2 TSs.

2.2 Optional Changes and Variations The proposed amendment is consistent with the STS changes described in TSTF-425, Revision 3. However, DNC proposes variations or deviations from TSTF-425, as identified below.

Serial No.14-434 Docket No. 50-336 Attachment 1, Page 2 of 5

1. Revised (typed) TS pages are not included in this amendment request given the number of TS pages affected, the straightforward nature of the proposed changes, and outstanding MPS2 amendment requests that may impact some of the same TS pages. Providing only mark-ups of the proposed TS changes satisfies the requirements of 10 CFR 50.90 in that the mark-ups fully describe the changes desired. This represents an administrative deviation from the NRC staffs model application dated July 6, 2009 (74 FR 31996) with no impact on the NRC staffs model safety evaluation published in the same Federal Register notice. As a result of this deviation, the contents and numbering of the attachments for this amendment request differ from the attachments specified in the NRC staffs model application.

The proposed TS Bases changes are provided to the NRC for information only.

2. The inserts provided in TSTF-425 are revised to fit the MPS2 TS format.

The TSTF-425 insert for each relocated surveillance frequency is changed from "in accordance with the Surveillance Frequency Control Program to "at the frequency specified in the Surveillance Frequency Control Program."

The insert provided in TSTF-425 to replace text describing the basis for each frequency relocated to the SFCP has been revised from "The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program" to read "The(se) Surveillance Frequency(ies) is/are controlled under the Surveillance Frequency Control Program." This deviation is consistent with NRC guidance. After NRC approval of the license amendment request (LAR) and as part of the LAR implementation, the existing MPS2 Bases information describing the basis for the relocated surveillance frequencies will also be relocated to a licensee-controlled program with the relocated surveillance frequencies.

In addition, other editorial changes to the existing TS wording and/or text inserts are being made. These administrative/editorial deviations of the TSTF-425 inserts and the existing TS wording are made to fit the MPS2 TS format.

The approved programs for MPS2 are described in Section 6.0, "Administrative Controls," of the MPS2 TSs. The title descriptor in Table 4.7-2 (i.e., Secondary Coolant System Specific Activity Sample and Analysis "Program.") may be misconstrued since there are no program requirements for secondary coolant specific activity sampling and analysis in Section 6.0 of the MPS2 TSs. To preclude future misunderstanding, DNC proposes to delete the word 'Program" from the title in Table 4.7-2. This change is reflected in the mark-up for Table 4.7-2 provided in Attachment 3.

3. Attachment 4 provides a cross-reference between the NUREG-1432 surveillances included in TSTF-425 versus the MPS2 surveillances included in this amendment

Serial No.14-434 Docket No. 50-336 Attachment 1, Page 3 of 5 request. Attachment 4 includes a summary description of the referenced TSTF-425 (NUREG-1432)/MPS2 TS surveillances which is provided for information purposes only and is not intended to be a verbatim description of the TS surveillances. This cross reference highlights the following:

a. NUREG-1432 surveillances included in TSTF-425 and corresponding MPS2 surveillances with plant-specific surveillance numbers,

b. NUREG-1432 surveillances included in TSTF-425 that are not contained in the MPS2 TSs, and

c. MPS2 plant-specific surveillances that are not contained in NUREG-1432 and, therefore, are not included in the TSTF-425 mark-ups.

Since the MPS2 TSs are custom TSs, the applicable surveillance requirements and associated Bases numbers differ from the STSs presented in NUREG-1432 and TSTF-425, but with no impact on the NRC staffs model safety evaluation dated July 6, 2009 (74 FR 31996).

For NUREG-1432 surveillances not contained in MPS2 TSs, the corresponding mark-ups included in TSTF-425 for these surveillances are not applicable to MPS2.

This is an administrative deviation from TSTF-425 with no impact on the NRC staffs model safety evaluation dated July 6, 2009 (74 FR 31996).

For MPS2 plant-specific surveillances not included in the NUREG-1432 markups provided in TSTF-425, DNC has determined that since these surveillances involve fixed periodic frequencies, relocation of these frequencies is consistent with TSTF-425, Revision 3, and with the NRC's model safety evaluation dated July 6, 2009 (74 FR 31996), including the scope exclusions identified in Section 1.0, "Introduction," of the model safety evaluation. In accordance with TSTF-425, changes to the frequencies for these surveillances would be controlled under the SFCP.

There are several instances in the MPS2 TSs where the words 'and' and 'or' appear at the end of a surveillance requirement. In most cases, these words are not intended to be logical connectors which place the constraints of the preceding surveillance requirement (often times event-driven) on the remaining portion of the surveillance but rather are used for purposes of readability and flow. This situation applies to the following SRs: 4.1.1.2, 4.1.3.1.1, 4.1.3.1.4b, 4.2.3.2b, 4.5.1d, 4.9.16 and 4.9.17.

As currently written, SR 4.2.1.3b does not specify a surveillance frequency, however; it is performed at least once per 31 days, as required by its applicable station surveillance procedure. As a result, the markup for this SR references the SFCP in accordance with TSTF-425.

Serial No.14-434 Docket No. 50-336 Attachment 1, Page 4 of 5 The SFCP provides the necessary administrative controls to require that surveillances related to testing, calibration, and inspection are conducted at a frequency to assure the necessary quality of systems and components is maintained, facility operation will be within safety limits, and the limiting conditions for operation will be met. Changes to frequencies in the SFCP would be evaluated using the methodology and PRA guidelines contained in NEI 04-10, Revision 1, "Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies" (ADAMS Accession No. ML071360456), as approved by NRC letter dated September 19, 2007 (ADAMS Accession No. ML072570267). The NEI 04-10, Revision 1 methodology includes qualitative considerations, risk analyses, sensitivity studies and bounding analyses, as necessary, and recommended monitoring of the performance of structures, systems, and components (SSCs) for which frequencies are changed to assure that reduced testing does not adversely impact the SSCs. In addition, the NEI 04-10, Revision 1 methodology satisfies the five key safety principles specified in RG 1.177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications," dated August 1998, relative to changes in surveillance frequencies.

3.0 REGULATORY ANALYSIS

3.1 No Significant Hazards Consideration DNC has reviewed the proposed no significant hazards consideration (NSHC) determination published in the Federal Register dated July 6, 2009 (74 FR 31996).

DNC has concluded that the proposed NSHC presented in the Federal Register notice is applicable to MPS2, and is provided as Attachment 5 to this amendment request, which satisfies the requirements of 10 CFR 50.91 (a).

3.2 Applicable Regulatory Requirements A description of the proposed changes and their relationship to applicable regulatory requirements is provided in TSTF-425, Revision 3 and the NRC's model safety evaluation published in the Notice of Availability dated July 6, 2009 (74 FR 31996).

DNC has concluded that the relationship of the proposed changes to the applicable regulatory requirements presented in the Federal Register notice is applicable to MPS2.

3.3 Conclusions In conclusion, based on the considerations discussed above, (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 amendment will not be inimical to the common defense and security or to the health and safety of the public.

Serial No.14-434 Docket No. 50-336 Attachment 1, Page 5 of 5

4.0 ENVIRONMENTAL CONSIDERATION

DNC has reviewed the environmental consideration included in the NRC staffs model safety evaluation published in the Federal Register on July 6, 2009 (74 FR 31996).

DNC has concluded that the staffs findings presented therein are applicable to MPS2, and the determination is hereby incorporated by reference for this application.

5.0 REFERENCES

1. TSTF-425, Revision 3, "Relocate Surveillance Frequencies to Licensee Control -

RITSTF Initiative 5b," March 18, 2009 (ADAMS Accession Number:

ML090850642).

2. NRC Notice of Availability of Technical Specification Improvement to Relocate Surveillance Frequencies to Licensee Control - Risk-Informed Technical Specification Task Force (RITSTF) Initiative 5b, Technical Specification Task Force - 425, Revision 3, published on July 6, 2009 (74 FR 31996).

3. NEI 04-10, Revision 1, "Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies," April 2007 (ADAMS Accession Number: ML071360456).

4. Regulatory Guide 1.200, Revision 1, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities,"

January 2007 (ADAMS Accession Number: ML070240001).

5. Regulatory Guide 1.177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications," dated August 1998 (ADAMS Accession No. ML003740176).

Serial No.14-434 Docket No. 50-336 ATTACHMENT 2 Documentation of Probabilistic Risk Assessment (PRA)

Technical Adequacy DOMINION NUCLEAR CONNECTICUT, INC.

MILLSTONE POWER STATION UNIT 2

Serial No.14-434 Docket No. 50-336 Attachment 2, Page 1 of 14 Documentation of Probabilistic Risk Assessment (PRA)

Technical Adequacy Quality of the PRA Regulatory Guide (RG) 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," provides the regulatory guidance for assessing the technical adequacy of a probabilistic risk assessment (PRA) model. Revision 2 of this RG (Reference 1) endorses (with comments and qualifications) the use of American Society of Mechanical Engineers (ASME)/American Nuclear Society (ANS) RA-Sa-2009, "Addenda to ASME RA-S-2008 Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications," (Reference 2), NEI 00-02, "PRA Peer Review Process Guidelines," (Reference 3), and NEI 05-04, "Process for Performing Follow-On PRA Peer Reviews Using the ASME PRA Standard" (Reference 4). Revision 1 of this RG (Reference 5) had endorsed the internal events PRA standard ASME RA-Sb-2005, "Addenda to ASME RA-S-2002 Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications," (Reference 6). For the internal events PRA, there are no significant technical differences in the standard requirements between Revision 1 and Revision 2 of RG 1.200, and therefore assessments using the internal events standard of Revision 1 are acceptable.

To support approval and implementation of a Surveillance Frequency Control Program (SFCP) at Millstone Power Station Unit 2 (MPS2), Dominion Nuclear Connecticut, Inc.

(DNC) evaluated the MPS2 PRA model using the guidance of RG 1.200 to ensure it is capable of determining the change in -risk due to changes to surveillance frequencies of systems, structures and components (SSCs), using plant-specific data and models.

Capability Category II (CC II) of the standard is required by NEI 04-10 (Reference 7) for the internal events PRA. Any identified deficiencies to those requirements are further assessed to determine impacts to proposed changes to surveillance frequencies, including the use of sensitivity studies, where appropriate.

The MPS2 internal events PRA model received a formal industry peer review in 2000.

The purpose of the PRA peer review process is to provide a method for establishing the technical quality of a PRA model for the spectrum of potential risk-informed plant licensing applications for which the PRA model may be used. The PRA peer review process used a team composed of industry PRA and system analysts, each with significant expertise in both PRA development and PRA applications. This team.

provided both an objective review of the PRA technical elements and a subjective assessment, based on their PRA experience, regarding the acceptability of the PRA elements. The team used a set of checklists as a framework within which to evaluate the scope, comprehensiveness, completeness, and fidelity of the PRA products available. The MPS2 review team used the "Combustion Engineering Owner's Group (CEOG) Peer Review Process Guidance" as the basis for the review. This review was

Serial No.14-434 Docket No. 50-336 Attachment 2, Page 2 of 14 performed prior to issuance of an ASME PRA standard. With the exception of one significance level B finding and observation (F&O), the significance level A and B F&Os from this peer review have been resolved. NEI 05-04 characterizes only significance level A and B F&Os as "findings."

In 2007, DNC performed a self-assessment of the MPS2 internal events PRA model using the ASME PRA standard, ASME RA-Sb-2005, and the guidance in RG 1.200, Revision 1. This self-assessment was re-performed in 2011 using the updated ASME PRA standard, ASME/ANS RA-Sa-2009. Subsequently, in September 2012, Westinghouse completed a focused scope peer review of the upgraded PRA model of record, M209A, to evaluate its compliance with ASME/ANS RA-Sa-2009 and RG 1.200, Revision 2.

Open items and findings resulting from the CEOG industry peer review, DNC's self-assessments, and the Westinghouse focused scope peer review, are provided in Table

1. These open items and findings represent the gaps between DNC's internal events PRA model and the PRA standard supporting requirements (SRs). For each gap, the table provides the ASME/ANS SR, Review Type and Issue Description, Disposition, and Impact to MPS2 PRA Model and Resolution. Modeling gaps are classified as No Impact, Low Risk Significant, or Risk Significant to the application (based on their Fussell-Vesely (FV) importance value using a threshold value of 5E-3).

The findings identified in the 2012 peer review and the significance level A and B F&Os identified in the 2000 peer review that have been resolved are available for review.

PRA Model Maintenance and Update The MPS2 PRA model of record, M209Ac, and associated documentation have been maintained as a living program. The model is routinely updated approximately every 3 to 5 years to reflect the current plant configuration, additional plant operating history, and new component failure data. The M209Ac PRA model is highly detailed, including a wide variety of initiating events, modeled systems, operator actions, and common cause events. The PRA model quantification process used for the MPS2 PRA is based on the event tree/fault tree methodology, which is a well-known methodology in the industry.

Dominion employs a structured approach to establishing and maintaining the technical adequacy and plant fidelity of the PRA models for the operating Dominion nuclear generating sites. This approach includes both a proceduralized PRA maintenance and update process, and the use of self-assessments and independent peer reviews. The following information describes this approach as it applies to the MPS2 PRA model.

There are several procedures and GARDs (Guidance and Reference Documentation) that govern Dominion's PRA program. These documents define the process to

Serial No.14-434 Docket No. 50-336 Attachment 2, Page 3 of 14 delineate the types of calculations to be performed, the computer codes and models used, and the process (or technique) by which each calculation is performed.

The NF-AA-PRA series of GARDs and procedures provide a detailed description of the methodology necessary to:

" Perform PRA for the Dominion nuclear fleet, including Millstone, North Anna and Surry Power Stations

" Create and maintain products to support licensing and plant operation concerns for the Dominion nuclear fleet

Provide PRA model configuration control

Create and maintain configuration risk evaluation tools for the Dominion nuclear fleet An administratively controlled process is used to maintain configuration control of the MPS2 PRA models, data, and software. In addition to model control, administrative mechanisms are in place to assure that plant modifications, procedure changes, system operation changes, and industry operating experience (OE) are appropriately screened, dispositioned and scheduled for incorporation into the model in a timely manner. These processes help assure that the MPS2 PRA reflects the as-built, as-operated plant within the limitations of the PRA methodology.

The PRA model is periodically reviewed and updated to incorporate any changes in plant design or operation. Plant modifications and procedure changes are reviewed periodically to determine if they impact PRA model and if any PRA modeling and/or documentation changes are warranted. These reviews are documented, and if any PRA changes are potentially needed, they are added to the PRA Configuration Control (PRACC) database for PRA evaluation and implementation tracking.

Scope of the PRA Each proposed change to a relocated surveillance frequency will be evaluated using the guidance contained in NEI 04-10 to determine its potential impact on risk, due to impacts from internal events, fires, seismic, other external events, and from shutdown conditions. In cases where a PRA of sufficient scope or quantitative risk models are unavailable, either bounding analyses or other conservative quantitative evaluations will be performed. A qualitative screening analysis may be used when the surveillance frequency impact on plant risk is shown to be negligible or zero.

As noted above, MPS2 has an internal events PRA model which has received a peer review, self assessment, and a focused scope peer review, MPS2 does not have a PRA model for internal fire events or for external events. In accordance with NEI 04-10, Revision 1, the licensee will perform an initial qualitative screening analysis, and if the qualitative information is not sufficient, a bounding analysis will be performed. The bounding analysis will be performed in accordance with NEI 04-10, Revision 1, Step

Serial No.14-434 Docket No. 50-336 Attachment 2, Page 4 of 14 1Ob, and will be based on risk insights and analysis documented in the MPS2 Individual Plant Examination of External Events (IPEEE) report with consideration of the IPEEE accident sequences, as well as relevant OE and additional risk insights obtained since the IPEEE study, in the context of the current plant configuration and operation.

For shutdown events, a qualitative assessment of the changes in the surveillance frequencies will be performed using guidance from NEI 04-10, Revision 1.

PRA Methodology The PRA methodology used at MPS2 includes a determination of whether a SSC affected by a proposed change to a surveillance frequency is modeled in the PRA model. Where a SSC is directly or implicitly modeled, a quantitative evaluation of the risk impact is performed. The failure probability of the impacted SSCs, including the impact of the selected testing strategy (i.e., staggered or sequential testing) on common cause failure modes, is adjusted accordingly based on the proposed change to the surveillance frequency. Where a SSC is not modeled in the PRA, bounding analyses are performed to characterize the impact of the proposed change to the surveillance frequency. Potential impacts on the risk analyses due to screening criteria and truncation levels are addressed by sensitivity studies identified in NEI 04-10.

Assumptions for Time Related Failure Contributions Failure probabilities of SSCs modeled in the PRA model may include both a standby time-related contribution and a cyclic demand-related contribution. For SSCs affected by a proposed change to a surveillance frequency, NEI 04-10 guidance provides for adjustment of the time-related failure contribution. This is consistent with RG 1.177, Section 2.3.3, which permits separation of the failure rate contributions into demand and standby for evaluation of surveillance frequency changes. If the available data does not support distinguishing between the time-related failures and demand failures, then the change to a surveillance frequency is conservatively assumed to impact the total failure probability of the SSC, including both standby and demand contributions. The SSC failure rate (per unit time) is assumed to be unaffected by the change in test frequency and will be confirmed by the monitoring and feedback that is required after the surveillance frequency change is implemented. The process requires consideration of qualitative sources of information with regards to the potential impact of surveillance frequency changes on SSC performance, including; industry and plant-specific OE, vendor recommendations, industry standards, and code-specified test intervals.

Therefore, the process is not reliant upon risk analyses as the sole basis for the proposed changes.

The potential benefits of reduced surveillance frequency, which include reduced unavailability, less potential for restoration errors, reduced potential for test-caused

Serial No.14-434 Docket No. 50-336 Attachment 2, Page 5 of 14 transients, and reduced test-caused wear of equipment, will be qualitatively assessed, but not quantitatively assessed.

Sensitivity and Uncertainty Analyses In accordance with NEI 04-10, sensitivity studies will be performed to assess the impact of uncertainties from key assumptions of the PRA, uncertainty in the failure probabilities of the affected SSCs, impact on the frequency of initiating events, and any identified deviations from CC II of the PRA standard. When the sensitivity analyses identify a potential impact on a proposed change, revised surveillance frequencies are considered along with any qualitative considerations that could impact the results of the sensitivity studies. Continued monitoring and feedback of SSC performance is required once a revised surveillance frequency is implemented.

References

1. NRC Regulatory Guide 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities,"

Revision 2.

2. ASME/ANS RA-S-2008, "Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications" and its 2009 addendum (ASME/ANS RA-Sa-2009).

3. NEI 00-02, "Probabilistic Risk Assessment (PRA) Peer Review Process Guidance,"

Revision 1.

4. NEI 05-04, "Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard," Revision 3, dated November 2009.

5. NRC Regulatory Guide 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities,"

Revision 1.

6. ASME/ANS RA-S-2002, "Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications" and its 2005 addendum (ASME/ANS RA-Sb-2005).

7. NEI 04-10, "Risk-Informed Technical Specifications Initiative 5b - Risk-Informed Method for Control of Surveillance Frequencies - Industry Guidance Document,"

Revision 1, dated April 2007.

Serial No.14-434 Docket No. 50-336 Attachment 2, Page 6 of 14 Table 1 MPS2 PRA Model Gaps Gap SR Review Type & Issue Description Disposition Impact to MPS2 PRA Model & Resolution 1 Observation 2000 CEOG Peer Review: Add the steam dump valves as a Impact: The model change is expected to have an ID: AS-10/ Main feedwater (MFW) success required support system for the MFW insignificant impact since four steam dump valves Sub-element criteria does not require makeup to function. provide sufficient redundancy and the MFW function AS-18 the condenser when steam dump relies on the same support systems as the steam valves fail. Documentation to verify dump valves (i.e., instrument air and circulating that adequate volume exists in the water).

condenser for successful cooldown is required. No modeling of makeup to Low Risk Significant the condenser was identified.

Resolution: Until this F&O is resolved, a sensitivity study will be performed by adding the steam dump valves as a required support system for the MFW function.

2 IE-A8 Self Assessment: Plant personnel Interviews with plant system engineers Impact: Based on results of the system engineer interviews to determine if potential were conducted and documented. As interviews, this is considered a documentation issue events have been overlooked were a result of these interviews, no new only and thus, there is no impact on the PRA model.

not properly documented. initiating events were required to be added to the PRA model. No impact After completing the system engineer Resolution: PRA procedure now requires interviews interviews, it was decided that since to be conducted regarding potential initiating events the group of interviewee's did not and past operating experience.

include Operations personnel, this SR was only partially met. This SR will This SR will continue to remain as not met until similar remain as not met until similar interviews are conducted with Operations personnel.

interviews are conducted with Operations personnel.

3 AS-A7 Self Assessment: Anticipated These issues have been resolved with Impact: The impact of adding this consequential Transient Without Scram (ATWS) the exception of power restoration SGTR event to the PRA model is not expected to be does not consider the time of adverse following an SBO. significant since the frequency of the transfer branch moderator temperature coefficient (SBO with failure of TDAFW pump and consequential (MTC). Loss of seal cooling, loss of For power restoration following an SGTR) is much lower than the frequency of the SGTR all alternating current (i.e., station SBO, restarts of required accident initiating event.

Serial No.14-434 Docket No. 50-336 Attachment 2, Page 7 of 14 Table I MPS2 PRA Model Gaps Gap SR Review Type & Issue Description Disposition Impact to MPS2 PRA Model & Resolution blackout or SBO), inadvertent mitigation components will be opening of power-operated relief modeled. For SBO sequences with Low Risk Significant valves (PORVs) and safety relief failure of TDAFW pump and offsite valves (SRVs) are included in some, power recovery in time to prevent core Resolution: Until this F&O is resolved, a sensitivity but not all, event tree models. damage, when operators restore AFW study will be performed to model the restarts of Operator action to throttle auxiliary to dry/hot SGs, there is a potential for required accident mitigation components and a feedwater (AFW) after power consequential steam generator tube sensitivity study will be performed by adding a transfer restoration following an SBO is rupture (SGTR).This potential event from the SBO and subsequent loss of TDAFWP assumed successful. No justification will be added to the SBO event tree sequence to the consequential SGTR failure branch is provided for omitting this sequence. and also transferred to the of the SGTR event tree.

consequential SGTR branch of the SGTR event tree.

4 AS-A10 Self Assessment While differences This is a documentation issue. The Impact: Documentation issue only, no impact to PRA in system requirements for each model impact associated with this model.

initiating event may be included in the issue is covered by F&O HR-G4-01.

fault tree models, no explanation of (Gap #9) No impact how these differences impact operator actions or system responses This SR will remain open until HR-G4- Resolution: None, documentation issue only.

is provided. 01 is met; including any needed updates to the PRA notebooks.

5 AS-C2 Self Assessment: A one-to-one The documentation regarding the one- Impact: Documentation issue only, no impact to PRA correlation between each initiating to-one correlation between each model.

event and the associated event tree initiating event and the associated and the system success criteria and event tree needs to be completed. No impact associated basis is not clearly documented. A discussion of the This SR will remain not met until SRs Resolution: None, documentation issue only.

accident sequences pending AS-7 and AS-Al0 are met. (Gaps #3 resolution of issues associated with and 4) other AS SRs requires revision (AS-A7). Operator actions and any associated dependencies on system success are not clearly explained (AS-Al 0).

Serial No.14-434 Docket No. 50-336 Attachment 2, Page 8 of 14 Table I MPS2 PRA Model Gaps Gap SR Review Type & Issue Description Disposition Impact to MPS2 PRA Model & Resolution 6 SY-A4, Self Assessment: While the Interviews with system engineers were Impact: Based on results of the system engineer SY-C2 Individual Plant Examination (IPE) conducted to partially address this SR. interviews performed to date, this is considered a documentation and interviews with Additional interviews with Operations documentation issue only and therefore, there is no the PRA engineers indicate that the personnel and walk-downs will need to impact on the PRA model.

tasks in SY-A4 were performed, no be completed before this supporting documentation exists (walkdown requirement is met. No impact sheets, system engineer interviews) to support this supposition. Resolution: PRA procedure now requires interviews and walkdowns to be conducted and documented to confirm system analysis correctly reflects the as-built, as-operated plant.

7 SY-A21, Self Assessment: Supporting room Room heatup calculations have been Impact: The room cooling matrix is a visual SY-A22, heatup calculations are not well performed for the most risk significant representation of which ventilation systems are SY-C2 documented. Also, failure of rooms (i.e., the switchgear rooms), and modeled and what equipment is affected if the electrical load shedding and ventilation failures are included in the ventilation system fails. The matrix is used only for excessive humidity conditions that model, as appropriate. Components in documentation purposes and therefore, has no impact could lead to a loss of function were rooms requiring ventilation to the PRA model.

not addressed. dependencies are assumed to fail For example, PRA documentation upon loss of ventilation unless the The impact of adding the loss of DC switchgear room indicates that room cooling for the DC room heatup calculation showed chillers following a turbine building HELB to the model switchgear is needed only for otherwise. However, a room cooling is not expected to be significant since the required equipment which requires DC power matrix has not been included in the response to the event is to establish compensatory for more than one hour after an event notebook to show which areas have cooling to the DC rooms.

occurs. This analysis needs to be calculations completed.

reviewed. Low Risk Significant During the 2009 model update, the failure of load shedding was added to Resolution: Until this F&O is resolved, a sensitivity the electric power fault tree. However, study will be performed by including the loss of DC the effect of a Turbine Building high switchgear room chillers following a Turbine Building energy line break (HELB) on the direct HELB.

current (DC) switchgear room chillers needs to be considered for excessive humidity conditions.

Serial No.14-434 Docket No. 50-336 Attachment 2, Page 9 of 14 Table I MPS2 PRA Model Gaps Gap SR Review Type & Issue Description Disposition Impact to MPS2 PRA Model & Resolution The DC switchgear room cooling system is not modeled for components which only require DC power coincident with accident event initiation since the room temperature is expected to be below the maximum allowable when the initiating event occurs. DC switchgear room cooling is modeled for equipment requiring DC power after the initiating event occurs.

8 HR-G3 Focused Scope Peer Review: The HRA calculator worksheets have Impact: Potentially higher HEPs may result in an Two sections in the Human Reliability been corrected in a draft file. A new increase in core damage frequency (CDF) and Large Finding Analysis (HRA) calculator worksheets dependency analysis will be performed Early Release Frequency (LERF).

F&O: were identified as not being properly using the HRA calculator with the HR-G3-01 filled out, i.e., dependency factor and corrected human error probabilities Risk Significant sigma. (HEPs). Then the MPS2 model will be quantified using the new HEP values. Resolution: Correct the HRA Calculator entries for dependency factor and sigma and then perform a This F&O will remain open until the sensitivity study with corrected HEPs.

new HRA calculations are included in the MPS2 PRA model.

9 HR-G4 Focused Scope Peer Review: This F&O will remain open until the Impact: Potentially higher HEPs may result in an HEP timing information for HRA event specific concern is addressed, the increase in CDF and LERF.

Finding OAADV1 showed two different times extent of condition review for other F&O: associated with this event; 30 HRA events is completed, and HEPs Risk Significant HR-G4-01 minutes for General Transient and 11 are corrected for any issues identified minutes for Loss of Main Feedwater. during the extent of condition review. Resolution: A sensitivity study will be performed with Since 11 minutes is limiting, use of a combination of corrected HEPs.

the 30 minute time for Tsw for OAADV1, could be non-conservative.

Serial No.14-434 Docket No. 50-336 Attachment 2, Page 10 of 14 Table I MPS2 PRA Model Gaps Gap SR Review Type'& Issue Description Disposition Impact to MPS2 PRA Model & Resolution-.

This has the potential to have an impact on HFE quantifications.

For HEPs, where time available varies depending on the event sequence, provide a justification if the shorter time is not used.

Spot checks of several other HRA events indicated that the example above is not an isolated case. The source of information for timing of operator actions should be accurately identified and clearly documented.

I +/- 4 4 10 LE-C2, Focused Scope Peer Review: (1) For the SGTR scenario, the SAMG Impact: The impact of item 1 results in an LE-C7 The MPS2 Severe Accident Mitigation operator action to feed a dry steam insignificant decrease in LERF. The operator action to Guidelines (SAMGs) were evaluated generator for scrubbing of fission feed a dry steam generator for scrubbing of fission Finding F&O to determine what post-core damage products has not yet been added to the products needs to be realistically treated.

LE-C2-01 operator actions might be credited. MPS2 model.

Of the 10 operator actions in the The impact of item 2 results in an insignificant SAMGs, only two were found to be (2) The valves in the containment increase in LERF after the model is changed to potentially applicable to post-core isolation analysis, identified as having remove the MOVs requiring manual action to close.

damage credit. Of these two operator implied operator actions, are actions, the HEP for the SGTR associated with containment spray and Low Risk Significant scenario was set to 1.0 based on safety injection. These motor operated timing concerns (time to perform vs. valves (MOVs), which are in series Resolution: (1) Until this F&O is resolved, a time available). The other operator with check valves, do not get a sensitivity study will be performed by realistically action for the containment isolation containment isolation signal to close modeling the SAMG operator action to feed a dry failure analysis was determined to be and, as such, should not have been steam generator.

feasible but could not be located. credited in the containment isolation analysis. These valves should be removed from the analysis and (2) Until this F&O is resolved, a sensitivity study will Also, some implied operator actions be performed by removing credit for closing the in the containment isolation failure therefore, no HEP calculation is

Serial No.14-434 Docket No. 50-336 Attachment 2, Page 11 of 14 Table I MPS2 PRA Model Gaps Gap

SR Review Type & Issue Description Disposition Impact to MPS2 PRA Model & Resolution analysis did not appear to have been required for the operator action to containment spray and safety injection MOVs in the addressed. close the MOVs. containment isolation analysis.

Either calculate the HEP for the remaining HFE and include it in the model or document a basis for not including it in the model. Also, explain the operator actions implied in the containment isolation failure analyses and include these in the model with the HEPs. Two alternatives are to demonstrate and document that there are no applicable operator actions to be modeled or to include the actions in the model with a HEP screening value of 1.0 11 LE-F1 Focused Scope Peer Review: The dominant LERF contributors to Impact: Documentation issue only. This change will There is no quantitative evaluation LERF needs to be presented by plant have no effect on the LERF results that are currently Finding F&O and identification of the dominant damage state, which requires provided in the PRA model except to provide another LE-FI-01 LERF contributors to LERF by plant enhancements to the CAFTA LERF way to present the results.

damage states. model. This may be done in the next model update. However, this will have No impact no effect on LERF results other than to provide another way to present the Resolution: None, documentation issue only.

results.

12 IFPP-A4 Focused Scope Peer Review: EPRI Report 1019194, Guidelines for Impact: Use of non-conservative assumptions may Assumptions of 30 inches and 2 Performance of Internal Flooding PRA, result in an increase in CDF and LERF.

Finding F&O: hours for non-water tight doors do-not December 2009, states that if door reflect the as-operated plant failure calculations are not available, Risk Significant IFPP-A4-01 configuration which could lead to the door failure flood height should be

Serial No.14-434 Docket No. 50-336 Attachment 2, Page 12 of 14 Table I MPS2 PRA Model Gaps Gap SR Review Type & Issue Description Disposition Impact to MPS2 PRA Model & Resolution potential non-conservative modeling. 3 feet or less for doors that open into Resolution: Until this F&O is resolved, a sensitivity the flood area and 1 foot or less if the study will be performed by using water height door Either perform more realistic door opens out of the flood area. failure criteria from EPRI Report 1019194, December modeling or recognize the 2009.

assumptions as uncertainties and The MPS2 PRA model will be updated perform sensitivity studies. to either use water height door failure criteria from EPRI Report 1019194 or use criteria generated from door failure calculations.

The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months criterion is addressed in IFSN-A14-01 (Gap #15).

13 IFSO-A3 Focused Scope Peer Review: See SR IFSN-A14-01 (Gap #15) and See SR IFSN-A14-01 (Gap #15) and IFPP-A4-01 Assumptions of 30 inches and 2 IFPP-A4-01 (Gap #12) for disposition. (Gap #12) for impact and resolution.

Finding F&O: hours for non-water tight doors could lead to potential non-conservative IFSO-A3-01 modeling.

14 IFSN-A8 Focused Scope Peer Review: Drains with check valves and Impact: There is the possibility a new propagation Two conditions specified by the SR hatchways at MPS2 will be path will be identified that either changes an existing Finding F&O: are not identified or documented. documented in a PRA Notebook to flood scenario or requires adding a new flood They are - IDENTIFY inter-area resolve this item. scenario to the model.

IFSN-A8-01 propagation through:

1. Areas connected via backflow [Potentially]Risk Significant through drain lines involving Resolution: If new propagation pathways or flooding failed check valves, scenarios are identified, a sensitivity study will be

2. Hatchways performed to include propagation through hatchways These conditions could be screened or areas connected via backflow through drain lines out later; however, they need to be involving failed check valves.

identified first.

Serial No.14-434 Docket No. 50-336 Attachment 2, Page 13 of 14 Table I MPS2 PRA Model Gaps Gap SR Review Type & Issue Description Disposition Impact to MPS2 PRA Model & Resolution 15 IFSN-A14, Focused Scope Peer Review: This item applies to both SR IFSN-A14 Impact: If appropriate justification is not provided for IFSN-A16 The 2-hour isolation criteria for plant and IFSN-A16. screening out flood areas in accordance with this SR, mitigative actions assumed an increase in CDF and LERF may result.

Finding qualitatively that sufficient time is The PRA procedure has been revised F&O: available to perform the isolation. to better align with the criteria stated in Risk Significant Justification is needed for the 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months the standard. The review of the 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months IFSN-A14-01 assumption to meet the SR CCI or isolation criteria against this revised Resolution: Until this F&O is resolved, a sensitivity CCII requirements. PRA procedure has not been study will be performed by using the criteria provided completed. in the revised PRA procedure.

If appropriate justification is not provided for screening out flood areas in accordance with this SR, the MPS2 model will be revised.

This F&O will remain open until the review has been completed and the model and documentation has been updated, if necessary, to meet the revised PRA procedure.

16 IFEV-A5 Focused Scope Peer Review: The current MPS2 model was issued Impact: Failure to use the latest available industry The MPS2 model did not reflect the before issuance of the 2013 EPRI data for pipe break frequencies may result in an Finding F&O: most recent pipe break frequencies. Report 300200079 for pipe rupture increase in CDF and LERF Documented assessment is needed frequencies. The next model update iFEV-A5-01 to ensure the pipe break frequency will include the latest available pipe Risk Significant data used complies with the rupture frequencies.

applicable requirement in Section 2- Resolution: Until this F&O is resolved, a sensitivity 2.1 of ASME/ANS RA-Sa-2009. This F&O will remain open until the study will be performed to use the latest available next model update is completed. industry data which is currently EPRI Report 3002000079 issued in 2013.

Serial No.14-434 Docket No. 50-336 Attachment 2, Page 14 of 14 Table 1 MPS2 PRA Model Gaps Gp SR. j E-6Ipc:Nn.Ti Review Type & Issue Description Disposition j mpact to MPS2 PRA Model &.Resolution sadcmnainiseoln 17 IFEV-A6 Focused Scope Peer Review: Plant specific information was collected Impact: None. This is a documentation issue only, no Finding F&O: The MPS2 model used only generic and considered in determining flood impact to PRA model.

pipe rupture frequencies. To satisfy initiating event frequencies. No IFEV-A6-01 CC II, both generic and plant specific adverse trends were found that No Impact data sources are required. required Bayesian updating of the generic pipe break frequencies. This Resolution: None, documentation issue only. A evaluation was not documented at the search of plant specific information during the most time of the peer review.

recent model update relevant to pipe rupture frequencies did not identify any adverse trends.

A PRA procedure was revised to improve the guidance and to clarify that reviews should be documented regardless of whether any relevant adverse trends were found in the search of plant specific data.

This F&O will remain open until another search of plant specific information relevant to pipe rupture frequencies is completed and documented in the next MPS2 model update which is scheduled to begin in 2014. If any relevant adverse trends are found they will be considered in determining pipe rupture frequencies.

Serial No.14-434 Docket No. 50-336 ATTACHMENT 3 Marked-up Technical Specifications Chanaes DOMINION NUCLEAR CONNECTICUT, INC.

MILLSTONE POWER STATION UNIT 2

Ozteber-27, 2008 INDEX DEFINITIONS SECTION PAGE 1.0 DEFINITIONS Defined Term s .................................................................................................................. 1-1 Therm al Power ................................................................................................................ 1-1 Rated Therm al Pow er ....................................................................................................... 1-1 Operational M ode ............................................................................................................. 1-1 Action ............................................................................................................................... 1-1 Operable - Operability ...................................................................................................... 1-1 Reportable Event .............................................................................................................. 1-1 Containm ent Integrity ...................................................................................................... 1-2 Channel Calibration ........................................................................................................ 1-2 Chanm el Check ................................................................................................................. 1-2 Channel Functional Test ................................................................................................... 1-2 Core Alteration ................................................................................................................. 1-3 Shutdown M argin .............................................................................................................. 1-3 Leakage ............................................................................................................................ 1-3 Azim uthal Power Tilt ....................................................................................................... 1-4 Dose Equivalent 1-131 ...................................................................................................... 1-4 Dose Equivalent Xe- 133 ................................................................................................. 1-4 Stagger d T Ba i......................................................................................................... . 4 Frequency N otation .......................................................................................................... 1-4 Axial Shape Index ........................................................................................................... 1-5 Core Operating Lim its Report .......................................................................................... 1-5 MILLSTONE - UNIT 2 I Amendment No. 9, *, 4-04, 444, 448, 299,30-7

T..ne- 2' *2*1*

INDEX ADMINISTRATIVE CONTROLS SECTION PAGE 6.22 REACTOR COOLANT PUMP FLYWHEEL INSPECTION PROGRAM .................... 6-28 6.23 TECHNICAL SPECIFICATION (TS) BASES CONTROL PROGRAM ...................... 6-28 6.24 DIESEL FUEL OIL TEST PROGRAM .......................................................................... 6-29 6.25 PRE-STRESSED CONCRETE CONTAINMENT TENDON SURV EILLAN CE PROG RA M ..................................................................................... 6-29 6.26 STEAM GENERATOR PROGRAM ............................................................................... 6-30 6.27 CONTROL ROOM HABITABILITY PROGRAM ......................................................... 6-32 6.28 SNUBBER EXAMINATION, TESTING, AND SERVICE LIFE M ON ITO RIN G PRO G RA M ......................................................................................... 6-33 I--16.29 Surveillance Frequency Control Program .................................................... 6-331 MILLSTONE - UNIT 2 XVIII Amendment No. 2-7-9, 299, 3-05, 3-4-"

Oetober-27, 2008 DEFINITIONS AZIMUTHAL POWER TILT - Tq 1.18 AZIMUTHAL POWER TILT shall be the difference between the maximum power generated in any core quadrant (upper or lower) and the average power of all quadrants in that half (upper or lower) of the core divided by the average power of all quadrants in that half (upper or lower) of the core.

AZIMUTHALPOWERTILT [Maximum power in any core quadrant (upper or lower)-]

L Average power of all quadrants (upper or lower) _

DOSE EQUIVALENT 1-131 1.19 DOSE EQUIVALENT 1-131 shall be that concentration of 1-131 (micro-curie/gram) that alone would produce the same dose when inhaled as the combined activities of iodine isotopes I-131, 1-132, 1-133, 1-134, and 1-135 actually present. The determination of DOSE EQUIVALENT 1-131 shall be performed using Committed Dose Equivalent (CDE) or Committed Effective Dose Equivalent (CEDE) dose conversion factors from Table 2.1 of EPA Federal Guidance Report No.

11, "Limiting Values of Radionuclide Intake and Air Concentration and Dose Conversion Factors for Inhalation, Submersion and Ingestion."

DOSE EQUIVALENT XE-133 1.20 DOSE EQUIVALENT XE-133 shall be that concentration of Xe-133 (micro-curie/gram) that alone would produce the same acute dose to the whole body as the combined activities of noble gas nuclides Kr-85m, Kr-85, Kr-87, Kr-88, Xe-131m, Xe-133m, Xe-133, Xe-135m, Xe-135, and Xe-138 actually present. If a specific noble gas nuclide is not detected, it should be assumed to be present at the minimum detectable activity. The determination of DOSE EQUIVALENT XE- 133 shall be performed using effective dose conversion factors for air submersion listed in Table 111. 1 of EPA Federal Guidance Report No. 12, 1993, "External Exposure to Radionuclides in Air, Water, and Soil."

STAGGERED TEST BA&IS DELET ED 1.21 1A iG-G-EIR E-9.. BBAS, S shallW ofi.

a-. A test sehedttle for-n systems, stibsystemis, fr-ains or other designated eempenent-s obtained by div-iding the specified test intenval into n equal suibinten'al, and b- The testing of one system, subsystem, tr-ain or: other-designated eempenent at the beginning of eaeh subintenval.

FREQUENCY NOTATION 1.22 The FREQUENCY NOTATION specified for the performance of Surveillance Requirements shall correspond to the intervals defined in Table 1.2.

MILLSTONE - UNIT 2 1-4 Amendment No. 4-04, 2-1-6, 298, 3O0

ttgu1 St 17, 995 or-igiflatk-ji iffif alY+ 4, 9 8 6 TABLE 1.2 FREQUENCY NOTATION NOTATION FREQUENCY S At least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

D At least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

w At least once per 7 days.

M At least once per 31 days.

Q At least once per 92 days.

SA At least once per 6 months.

R At least once per 18 months.

S/U Prior to each reactor startup.

P Prior to each release.

N.A. Not applicable.

JSFC At the frequency specified in the Surveillance Frequency Control Program.

MILLSTONE - UNIT 2 1-9 Amendment No. 4-04 .k

September 25, 2003 3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1 REACTIVITY CONTROL SYSTEMS SHUTDOWN MARGIN - (SDM)

LIMITING CONDITION FOR OPERATION 3.1.1.1 The SHUTDOWN MARGIN shall be within the limit specified in the CORE OPERATING LIMITS REPORT.

APPLICABILITY: MODES 3(I)*, 4 and 5.

ACTION:

With the SHUTDOWN MARGIN not within the limit specified in the CORE OPERATING LIMITS REPORT, within 15 minutes, initiate and continue boration at > 40 gpm of boric acid solution at or greater than the required refueling water storage tank (RWST) concentration (ppm) until the SHUTDOWN MARGIN is restored to within limit.

SURVEILLANCE REQUIREMENTS 4.1.1.1 Verify SHUTDOWN MARGIN is within the limit specified in the CORE OPERATING LIMITS REPORT at least ene. evef; 24 heurn.

the frequency specified in the Surveillance Frequency Control Program

(')See Special Test Exception 3.10.1 MILLSTONE - UNIT 2 3/4 1-1 Amendment No. 33, 61, 72, 74, 39, 4-48, 2-80

September- 25, 2003 3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1 REACTIVITY CONTROL SYSTEMS REACTIVITY BALANCE //

LIMITING CONDITION FOR OPERATION /

3.1.1.2 The core reactivity balance shall be within +/- 1% Ak/k of predicted values.

APPLICABILITY: MODES 1 and 2.

ACTION:

With core reactivity balance not within limit:

Re-evaluate core design and safety analysis and determine that the reactor core is acceptable for continued operation and establish appropriate operating restrictions and Surveillance Requirements within 7 days or otherwise be in MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

/

SURVEILLANCE REQUIREMENTS 4.1.1.2 Verify*(') overall core reactivity balance is within +/- 1% Ak/k of predicted values prior to entering MODE 1 after fuel loading and atc,,, ... n.. every 3 1 Effc.ti.v. Full Pew. Bys**).

The provisions of Specification 4.0.4 are not 'pplicable.

Ithe frequency specified in the Surveillance Frequency Control Program I

(1) The predicted reactivity values may be adjusted (normalized) to correspond to the measured core reactivity prior to exceeding a fuel bumup of 60 Effective Full Power Days after each fuel loading.

- (2) Only required after 60 Effective Full Power Days.

MILLSTONE - UNIT 2 3/4 1-3 Amendment No. 448, 72'0"

Sepember 25 20 REACTIVITY CONTROL SYSTEMS ACTION: (Continued):

C. CEA Deviation Circuit C. 1 Verify the indicated position of each CEA to be within inoperable. 10 steps of all other CEAs in its group within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and every 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months thereafter or otherwise be in MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

D. One or more CEAs untrippable. D. 1 Be in MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

OR Two or more CEAs misaligned by

> 20 steps.

SURVEILLANCE REQUIREMENTS 4.1.3.1.1 Verify the indicated position of each CEA to be within 10 steps of all other CEAs in its group a ast ence per- 12 hors AND within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months following any CEA movement ger than 10 steps.

4.1.3.1.2 Verify CEA fr edom of movement (trippability) by moving each individual CEA that is not fully serted into the reactor core 10 steps in either direction a k'ast one per 92-days.

4.1.3.1.3 Verify the CEA De iation Circuit is OPERABLE at by a functional test of the CEA group Deviation Circuit vhich verifies at the circuit prevents any CEA fro being misaligned from all ther CEAs i its group by more than 10 steps (indicate position).

4.1.3.1.4 Verify the CEA Motion I ibit is OPERABLE y a functi al test which verifies that the circuit maintains t e CEA group overl and se encing requirements of Specification 3.1.3.6 and th t the circuit preve ts regul ing CEAs from being inserted beyond the Transie Insertion Limit specif d in the CORE OPERATING LIMITS REPORT:

a. Prior to each entry into DE 2 fro M DE 3, except that such verification need not be performed mo often t an nce per 31 days, and

b. At I r I the frequency specified in the Surveillance Frequency Control Program I MILLSTONE - UNIT 2 3/4 1-21 Amendment No. 3-2-<-280

September 25, 2'U3 REACTIVITY CONTROL SYSTEMS POSITION INDICATOR CHANNELS (Continued)

LIMITING CONDITION FOR OPERATION (Continued) b) The CEA group(s) with the inoperable indicator is fully inserted, and subsequently maintained fully inserted, while maintaining the withdrawal sequence and THERMAL POWER level required by Specification 3.1.3.6 and when this CEA group reaches its fully inserted position, the "Full In" limit of the CEA with the inoperable position indicator is actuated and verifies this CEA to be fully inserted. Subsequent operation shall be within the limits of Specification 3.1.3.6.

4. If the failure of the position indicator channel(s) is during STARTUP, the CEA group(s) with the inoperable position indicator channel must be moved to the "Full Out" position and verified to be fully withdrawn via a "Full Out" indicator within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

c. With a maximum of one reed switch position indicator channel per group or one pulse counting position indicator channel per group inoperable and the CEA(s) with the inoperable position indicator channel at either its fully inserted position or fully withdrawn position, operation may continue provided:

1. The position of this CEA is verified immediately and at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter by its "Full In" or "Full Out" limit (as applicable).

2. The fully inserted CEA group(s) containing the inoperable position channel is subsequently maintained fully inserted, and

3. Subsequent operation is within the limits of Specification 3.1.3.6.

d. With one or more pulse counting position indicator channels inoperable, operation in MODES 1 and 2 may continue for up to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months provided all of the reed switch position indicator channels are OPERABLE.

SURVEILLANCE REQUIREMENTS jrequired[

4.1.3.3 Eachposition indicator channel shall be determined to be OPERABLE by verifying the pulse counting position indicator channels and the reed switch position indicator channels agree within 6 steps at Qr-12 har-,.

I the frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 1-25 Amendment No. 4-54, 2 September- 25, 2003 REACTIVITY CONTROL SYSTEMS CEA DROP TIME LIMITING CONDITION FOR OPERATION 3.1.3.4 The individual CEA drop time, from a fully withdrawn position, shall be <2.75 seconds from when electrical power is interrupted to the CEA drive mechanism until the CEA reaches its 90 percent insertion position with:

a. Tavg > 515' F, and

b. All reactor coolant pumps operating.

APPLICABILITY: MODES I and 2.

ACTION:

With the drop time of any CEA determined to exceed the above limit, restore the CEA drop time to within the above limit prior to proceeding to MODE 1 or 2.

SURVEILLANCE REQUIREMENTS 4.1.3.4 The CEA drop time shall be demonstrated through measurement with Tavg > 5150 F, L and all reactor coolant pumps operating prior to reactor criticality:

a. For all CEAs following each removal of the reactor vessel head,

b. For specifically affected individual CEAs following any maintenance on or modification to the CEA drive system which could affect the drop time of those specific CEAs, and

c. At least ... 18 .. nth,.

pr the frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 1-26 Amendment No. -3, 62, 90, 2-16,-2-8S-

Sceptcmbcr*1, 25, 2003 REACTIVITY CONTROL SYSTEMS SHUTDOWN CEA INSERTION LIMIT LIMITING CONDITION FOR OPERATION 3.1.3.5 All shutdown CEAs shall be withdrawn to > 176 steps.

/

APPLICABILITY: MODE 1*(1) /

MODE 2( 1),(2)** with any regulating CEA not fully inserted.

ACTION:

INOPERABLE EQUIPMENT REQUIRED ACTION A. One or more shutdown CEAs not A. 1 Restore shutdown CEA(s) to within limit, within limit within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or otherwise be in MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . I

/

SURVEILLANCE REQUIREMENTS 4.1.3.5 Verify each shutdown CEA is withdrawan >_176 steps at lcast o-tcc pcr 12 ho.rs.

Ithe frequency specified in the Surveillance Frequency Control Program

(I) This LCO is not applicable while performing Specification 4.1.3.1.2.

- (2)See Special Test Exceptions 3.10.1 and 3.10.2.

MILLSTONE - UNIT 2 3/4 1-27 Amendment No. 2-H

Supitiiibm 25, 2003 CrAsiatpa nr-rN I pttv atcl' :1 01 REACTIVITY CONTROL SYSTEMS REGULATING CEA INSERTION LIMITS (Continued)

B. Regulating CEA groups B. 1 Verify Short Term Steady State Insertion Limits as inserted between the Long Term specified in the CORE OPERATING LIMITS REPORT Steady State Insertion limit and are not exceeded within 15 minutes or otherwise be in the Transient Insertion Limit MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

specified in the CORE OPERATING LIMITS REPORT OR for intervals > 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months per 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months interval. B.2 Restrict increases in THERMAL POWER to < 5%

RATED THERMAL POWER per hour within 15 minutes or otherwise be in MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

C. Regulating CEA groups C. 1 Restore regulating CEA groups to within the Long inserted between the Long Term Term Steady State Insertion Limit specified in the CORE Steady State Insertion Limit and OPERATING LIMITS REPORT within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or the Transient Insertion Limit otherwise be in MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

specified in the CORE OPERATING LIMITS REPORT for intervals > 5 effective full power days (EFPD) per 30 EFPD or interval > 14 EFPD per 365 EFPD.

D. PDIL alarm circuit D. I Perform Specification 4.1.3.6.1 within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and inoperable. once per 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months thereafter or otherwise be in MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMENTS 4.1.3.6.1 Verify each regulating CEA group position is within the Transient Insertion Limits specified in the CORE OPERATING LIMITS REPORT at least oene per 12 t, .h.r The provisions of Specification 4.0.4 are not applicable entering into MODE 2 from MODE 3.

4.1.3.6.2 Verify the accumulated times during which the re.slating CEA groups are inserted

/

beyond the Steady State Insertion Limits but witlin the Transient Insertion Limits /

specified in the CORE OPERATING LIMITS/ EPORT 41east o1nc.@ per 24 heurs.

4.1.3.6.3 Verify PDIL alarm circuit is 01 MILLSTONE - UNIT 2 3/4 1-29 Amendment No. 448, 4--5-3, 2-4-6, 2 4antiafly 30, 2014 REACTIVITY CONTROL SYSTEMS CONTROL ROD DRIVE MECHANISMS LIMITING CONDITION FOR OPERATION 3.1.3.7 The control rod drive mechanisms shall be de-energized.

APPLICABILITY: MODES 3*, 4, 5 and 6, whenever the RCS boron concentration is less than refueling concentration of Specification 3.9.1.

ACTION:

With any of the control rod drive mechanisms energized, restore the mechanisms to their de-energized state within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or immediately open the reactor trip circuit breakers.

SURVEILLANCE REQUIREMENTS 4.1.3.7 -per-The control rod drive mechanisms shall be verified to be de-energized at least*,-ee 24h tdurs.

the frequency specified in the Surveillance Frequency Control Program The control rod drive mechanisms may be energized for MODE 3 as long as 4 reactor coolant pumps are OPERATING; the reactor coolant system temperature is greater than 5000 F, the pressurizer pressure is greater than 2000 psia and the requirements of Limiting Condition for Operation for Specification 3.3.1.1, "Reactor Protective Instrumentation," are met. t MILLSTONE - UNIT 2 3/4 1-31 Amendment No. 11*-291, 34-7

Sejptemb*r 1 25, 2003 POWER DISTRIBUTION LIMITS SURVEILLANCE REQUIREMENTS (Continued)

[the frequency specified in the Surveillance Frequency Control Program 4.2.1.2 Excore Detector Monitoring System*(') - The e ore detector monitoring system may 4-be used for monitoring the core power distribut

a. Verifying at enee p that e CEAs are withdrawn to and maintained at or beyond t ong Te Steady State Insertion Limits of Specification,3.1..6

b. Verifying at per31 that the AXIAL SHAPE INDEX alarm setpoints are adjusted to within e allowable limits specified in the CORE OPERATING LIMITS REPOff 4.2.1.3 Incore Detector Monitoring Sy tem**(2),***(3) - The incore detector monitoring system may be used for monitoring the c re power distribution by verifying that the incore detector Local Power Density alarms:

a. Are adjusted to sati the requirements of the core power distribution map which shall be updated at lcast cncc per-31 days.

b. Have their alarm setpoint adjusted to less than or equal to the limits specified in the L CORE OPERATING LIMITS REPORT.

lat the frequency specified in the Surveillance Frequency Control Program,

(')Only required to be met when the Excore Detector Monitoring System is being used to determine Linear Heat Rate.

- (2)Only required to be met when the Incore Detector Monitoring System is being used to determine Linear Heat Rate.

- - ( 3)Not required to be performed below 20% RATED THERMAL POWER.

MILLSTONE - UNIT 2 3/4 2-2 Amendment No. 2-7, -8, 5-2, 99, 4-39,

-144, 2-

NMhr-h 16, 2006 POWER DISTRIBUTION LIMITS TOTAL UNRODDED INTEGRATED RADIAL PEAKING FACTOR - FTr LIMITING CONDITION FOR OPERATION 3.2.3 The calculated value of FTr shall be within the 100% power limit specified in the CORE OPERATING LIMITS REPORT. The FTr value shall include the effect of AZIMUTHAL POWER TILT.

APPLICABILITY: MODE 1 with THERMAL POWER >20% RTP*.

ACTION:

With FTr exceeding the 100% power limit within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months either:

a. Reduce THERMAL POWER to bring the combination of THERMAL POWER and FTr to within the power dependent limit specified in the CORE OPERATING LIMITS REPORT and withdraw the CEAs to or beyond the Long Term Steady State Insertion Limits of Specification 3.1.3.6; or

b. Be in at least HOT STANDBY.

SURVEILLANCE REQUIREMENTS 4.2.3.1 The provisions of Specification 4.0.4 are not applicable.

4.2.3.2 FTr shall be determined to be within the 100% power limit at the following intervals:

a. Prior to operation above 70 percent of RATED THERMAL POWER after each fuel loading,

b. At p 3 joys of accumulated operati in MODE 1, and

c. Within ur hours if the AZIMUTHAL POWER TILT (Tq) is > 0.020.

4.2.3.3 FTr shall be deterned by using the incore detectors to obtain a power distribution map with all CEAs at or above t Long Term Steady State Insertion Limit for the existing Reactor Coolant Pump Combination.

the frequency specified in the Surveillance Frequency Control Program

See Special Test Exception 3.10.2.

MILLSTONE - UNIT 2 3/4 2-9 Amendment No. 38', 2, 7-9, 90, 99, 4-44, 4-39, 4-48, 4-55, 1-64, 2-30, 280, 2-94

March 16, 2006 POWER DISTRIBUTION LIMITS AZIMUTHAL POWER TILT - TQ LIMITING CONDITION FOR OPERATION 3.2.4 The AZIMUTHAL POWER TILT (Tq) shall be

0.02.

APPLICABILITY: MODE 1 with THERMAL POWER > 50% of RATED THERMAL POWER(')*.

ACTION:

a. With the indicated Tq > 0.02 but!_ 0.10, either restore Tq to

0.02 within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or verify the TOTAL UNRODDED INTEGRATED RADIAL PEAKING FACTOR (FTr) is within the limit of Specification 3.2.3 within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months and once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months thereafter. Or otherwise, reduce THERMAL POWER to

50% of RATED THERMAL POWER within the next 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

b. With the indicated Tq > 0.10, perform the following actions: (2)**

1. Verify the TOTAL UNRODDED INTEGRATED RADIAL PEAKING FACTOR (FTr) is within the limit of Specification 3.2.3 within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months ; and

2. Reduce THERMAL POWER to < 50% of RATED THERMAL POWER within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months ; and

3. Restore Tq

0.02 prior to increasing THERMAL POWER. Correct the cause of the out of limit condition prior to increasing THERMAL POWER.

Subsequent power operation above 50% of RATED THERMAL POWER may proceed provided that the measured Tq is verified

0.02 at least once per hour for 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , or until verified at 95% of RATED THERMAL POWER.

SURVEILLANCE REQUIREMENTS 4.2.4.1 Verify T is within limit at ast oncc cvc-ry 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The provisions of Specification 4.0.4 are not applicable for entering in,,ODE 1 with THERMAL POWER > 50% of RATED THERMAL POWER from MODE 1.

the freauencv specified in the Surveillance Frequencv Control Prowram

(')See Special Test Exception 3.10.2.

- (2 )All subsequent Required ACTIONS must be completed if power reduction commences prior ,1 to restoring Tq <_0.10.

MILLSTONE - UNIT 2 3/4 2-10 Amendment No. 8, 5-2, 90, 439,4-5-5, 2-80, 2-94

October~ 12, 1990 POWER DISTRIBUTION LIMITS DNB MARGIN LIMITING CONDITION FOR OPERATION 3.2.6 The DNB margin shall be preserved by maintaining the cold leg temperature, pressurizer pressure, reactor coolant flow rate, and AXIAL SHAPE INDEX within the limits specified in the CORE OPERATING LIMITS REPORT. '4, APPLICABILITY: MODE 1.

ACTION:

With any of the above parameters exceeding its specified limits, restore the parameter to within its above specified limits within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or reduce THERMAL POWER to < 5% of RATED THERMAL POWER within the next 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

SURVEILLANCE REQUIREMENTS t

4.2.6.1 The cold leg temperature, pressurizer pressure, and AXIAL SHAPE INDEX shall be determined to be within the limits specified in the CORE OPERATING LIMITS REPORT least onee per 12 ,hetiur. The reactor coolant flow rate shall be determined to be within the i it specified in the CORE OPERATING LIMITS REPORT at 4.2.6.2 The provisions of Specification 4.0.4 are not pplicable.y the frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 2-13 Amendment No. 3-8, 90, 44-3, 1 3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR PROTECTIVE INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.1.1 As a minimum, the reactor protective instrumentation channels and bypasses of Table 3.3-1 shall be OPERABLE.

APPLICABILITY: As shown in Table 3.3-1.

ACTION:

As shown in Table 3.3-1.

SURVEILLANCE REQUIREMENTS required 4.3.1.1.1 Each reactor protective instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL CALIBRATION and CHANNEL FUNCTIONAL TEST operations during the MODES and at the frequencies shown in Table 4.3-1.

4.3.1.1.2 The bypass function and automatic bypass removal function shall be demonstrated OPERABLE during a CHANNEL FUNCTIONAL TEST once within 92 days prior to each reactor startup. The total bypass function shall be demonstrated OPERABLE at least enee- pcr 1 menths during CHANNEL CALIBRATION testing of each channel affected bypass operation.

I 4.3.1.1.3 The REACTOR TRIP SYSTEM RESPONSE TIME of ea reactor trip function shall be demonstrated to be within its limit ateast ,n.e per 18 fn, nts.Neutron detectors are exempt from response time testing. Each test sý1 include at least on annel per function stieh that all re undant C 3ar.3 in a.sec ft II,*Jll.3Lflt1. .e"T-bta1NoIJIofehann-- s Ithe frequency specified in the Surveillance Frequency Control Program I MILLSTONE - UNIT 2 3/4 3-1 Amendment No. 72, 4-98, 29-1-, 3C1

lReplace each marked through surveillance frequency in the Check, Calibration, and Functional Test columns with "SFCP" I TA E 4.3-1 REACTOR PROTECTIVE INSTR ENTA IONSURVE ANCE REQUIREMENTS z

Z CHANNEL MODES IN WHICH CHANNEL CHANNEL FUNCTIONAL SURVE*ILLANCE FUNCTI(ONAL UNIT CHECK CALIBRATION TEST RE' QUIRED Manual Rea ctor Trip N.A. N.A. S/U(1) N.A.

2. Power Level - High

a. Nuclear Power -9(2), M(3),Q(5) -M- 1, 2,3*

b. AT Power 0-- 1

" 3. Reactor Coolant Flow - Low -S- -R 1,2

4. Pressurizer Pressure - High '-- 1,2

-Mv--

5. Containment Pressure - High 1,2

" -Mv-

6. Steam Generator Pressure - Low -R 1,2

-R

7. Steam Generator Water -'3- 1,2 Level - Low

8. Local Power Density - High -N- 1 CD 9. Thermal Margin/Low Pressure 1,2

10. Loss of Turbine--Hydraulic N.A. S/U(1) N.A.

ZS Fluid Pressure - Low 0

0)

D1

+/-

IReplace each marked through surveillance frequency in the Check, Calibration, and Functional Test columns with "SFCP" I TAB 1*-.

Cd)

REACTOR PROTECTIVE INST UMEN ATION SUR LLANCE REQUIREMENTS 0-z CHANNEL MODES IN WHICH CHANNEL CHANNEL FUNCTIONAL SURVEILLANCE FUNCTIONAL UNIT CHECK CALIBRATION TEST REQUIRED

11. Wide Range Logarithmic Neutron R(5) S/U(1) 3,4,5 Flux Monitor - Shutdown

12. DELETED

13. Reactor Protection System N.A. N.A. -M-and S/U(I) 1, 2 and

Logic Matrices

14. Reactor Protection System N.A. N.A. -M-and S/U(1) 1, 2 and

Logic Matrix Relays

15. Reactor Trip Breakers N.A. N.A. M 1, 2 and

CL

-1

janury 29,2008 INSTRUMENTATION 3/4.3.2 ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.2.1 The engineered safety feature actuation system instrumentation channels and bypasses shown in Table 3.3-3 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3-4.

APPLICABILITY: As shown in Table 3.3-3.

ACTION:

a. With an engineered safety feature actuation system instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3-4, either adjust the trip setpoint to be consistent with the value specified in the Trip Setpoint column of Table 3.3-4 within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or declare the channel inoperable and take the ACTION shown in Table 3.3-3.

b. With an engineered safety feature actuation system instrumentation channel inoperable, take the ACTION shown in Table 3.3-3.

SURVEILLANCE REQUIREMENTS

ýrequired 4.3.2.1.1 Each engineered safety feature actuation system instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL CALIBRATION and CHANNEL FUNCTIONAL TEST operations during the MODES and at the frequencies shown in Table 4.3-2.

4.3.2.1.2 The bypass function and automatic bypass removal function shall be demonstrated OPERABLE during a CHANNEL FUNCTIONAL TEST once within 92 days prior to each reactor startup. The total bypass function shall be demonstrated OPERABLE ,east-onv-e p menths during CHANNEL CALIBRATION testing of each channel aect y bypass operation.

1' Ithe frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 3-9 Amendment No. +-98, 282, 29+,3,0

September- 25, 2003 INSTRUMENTATION SURVEILLANCE REQUIREMENTS (Continued) 4.3.2.1.3 The ENGINEERED SAFETY FEATURES RESPONSE TIME of each ESF function shall be demonstrated to be within the limit at .... t .n.. per 18 m.nths. Each test shall include at least one channel per function suchteht ..............are tete ........... y N..........

men,, s where* NT

,*'is. .... tota dl ..... -tII ehnnl "f pefe S t ein sso ni 111t,.¢~~~~~~~~~~~~~

.r-t .L%..l~ll**O llJ' %J-W~Il ll..I*.

[the frequency specified in the Surveillance Frequency Control Program I MILLSTONE - UNIT 2 3/4 3-10 Amendment No. 49, 22-M, 24-5, 282

lReplace each marked through surveillance frequency in the Check, Calibration, and Functional Test columns with "SFCP" TABLE 4.3-R ENGINEERED SAFETY FEATURE ACTUATION SYST- IN RUME UVEILLANCE REQUIREMENTS ANNEL MODES IN WHICH CHANNEL CHANNEL FUNCTIONAL SURVEILLANCE Ci2 H

FUNCTIONAL UNIT CHECK CALIBRATION TEST REQUIRED 0 1. SAFETY INJECTION (SIAS) z a. Manual (Trip Buttons) N.A. N.A. N.A.

b. Containment Pressure - High -'3- -R-- 1,2,3

c. Pressurizer Pressure - Low -S -R 1, 2, 3

d. Automatic Actuation Logic N.A. N.A. 1,2,3

-R-

2. CONTAINMENT SPRAY (CSAS)

a. Manual (Trip Buttons) N.A. N.A. N.A.

b. Containment Pressure-- -S- -R- 1,2,3 High - High

c. Automatic Actuation Logic N.A. N.A. 1,2,3

-R

3. CONTAINMENT ISOLATION 0, (CIAS)

a. Manual CIAS (Trip Buttons) N.A. N.A. N.A.

b. Manual SIAS (Trip Buttons) N.A. N.A. N.A.

c. Containment Pressure - High -S- R -Rl 1,2,3

d. Pressurizer Pressure - Low -S- -R 1,2,3

e. Automatic Actuation Loic N.A. N.A. 1,2,3

4. MAIN STEAM LINE ISOLATION

a. Manual (Trip Buttons) N.A. N.A. N.A.

b. Containment Pressure - High -N-. -R- -R- 1,2,3 0-

c. Steam Generator Pressure - -R- 1,2, 3 Low z* d. Automatic Actuation Logic N.A. N.A. 1,2,3

-R4 0 5. ENCLOSURE BUILDING 2 FILTRATION (EBFAS)

a. Manual EBFAS (Trip Buttons) N.A. N.A. N.A.

b. Manual SIAS (Trip Buttons) N.A. N.A. N.A.

c. Containment Pressure - High -R 1,2,3 -I

d. Pressurizer Pressure - Low -N.- -R-- 1,2, 3 )

e. Automatic Actuation Logic N.A. N.A. 1,2, 3

)

lReplace each marked through surveillance frequency in the Check, Calibration, and Functional Test columns with "SFCP" I TABLE 4.3-2 (CJntinued)

CI) ENGINEERED SAFETY FEATURE ACTUATION SYSTE/'IN TRUQM TION SURVEILLANCE REOUIREMENTS H

0 ztll CHANNEL MODES IN WHICH N/

CHANNEL CHANNEL FUNCTIONAL SURVEILLANCE FUNCTIONAL UNIT CHECK CALIBRATION TEST REQUIRED

6. CONTAINMENT SUMP RECIRCULATION (SRAS)

a. Manual SRAS (Trip Buttons) N.A. N.A. N.A.

b. Refueling Water Sto-age -M 1,2, 3 Tank - Low

c. Automatic Actuation Logic N.A. N.A. -M(1) 1,2,3

7. DELETED

8. LOSS OF POWER

a. 4.16 kv Emergency Bus --S 1,2,3 Undervoltage - level one C:. b. 4.16 kv Emergency Bus -M 1,2, 3 Undervoltage - level two

9. AUXILIARY FEEDWATER z a. Manual N.A. N.A. N.A.

0

b. Steam Generator Level - Low -N-- N-R7 --M 1,2,3

c. Automatic Actuation Logic N.A. N.A. 1,2, 3 "t

10. STEAM GENERATOR BLOWDOWN

a. Steam Generator Level - Low -S- -vt 1,2,3 C

C C..

S -ptember-25, 2003 TABLE 4.3-2 (Continued)

Ithe frequency specified in the Surveillance Frequency Control Program TABLE NOTATION (1) The coincident logic circuits shall be tested automatically or m ally least once per-3-1

-days. The automatic test feature shall be verified OPERABLE a least once per 31 days.

The provisions of Specification 4.0.4 are not applicable for entry into MODE 3 or other specified conditions for surveillance testing of the following:

a. Pressurizer Pressure Safety Injection Automatic Actuation Logic; and

b. Pressurizer Pressure Containment Isolation Automatic Actuation Logic; and

c. Steam Generator Pressure Main Steam Line Isolation Automatic Actuation Logic; and

d. Pressurizer Pressure Enclosure Building Filtration Automatic Actuation Logic.

Testing of the automatic actuation logic for Pressurizer Pressure Safety Injection, Pressurizer Pressure Containment Isolation, and Pressurizer Pressure Enclosure Building Filtration shall be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after exceeding a pressurizer pressure of 1850 psia in MODE 3. Testing of the automatic actuation logic for Steam Generator Pressure Main Steam Line Isolation shall be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after exceeding a steam generator pressure of 700 psia in MODE 3.

MILLSTONE - UNIT 2 3/4 3-22 Amendment No. 6-7, 2--30, &2-

M~areh 16, 2006 INSTRUMENTATION ENGINEERED SAFETY FEATURE ACTUATION SYSTEM SENSOR CABINET POWER SUPPLY DRAWERS LIMITING CONDITION FOR OPERATION 3.3.2.2 The engineered safety feature actuation system Sensor Cabinets (RC02A1, RC02B2, RC02C3 & RC02D4) Power Supply Drawers shall be OPERABLE and energized from the normal power source with the backup power source available. The normal and backup power sources for each sensor cabinet is detailed in Table 3.3-5a:

CABINET NORMAL POWER BACKUP POWER RC02A 1 VA-10 VA-40 RC02B2 VA-20 VA-30 RC02C3 VA-30 VA-20 RC02D4 VA-40 VA-10 Table 3.3-5a APPLICABILITY: MODES 1, 2, 3 and 4 ACTION:

With any of the Sensor Cabinet Power Supply Drawers inoperable, or either the normal or backup power source not available as delineated in Table 3.3-5a, restore the inoperable Sensor Cabinet Power Supply Drawer to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in COLD SHUTDOWN within the next 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

SURVEILLANCE REQUIREMENTS lat the frequency specified in the Surveillance Frequency Control Program 4.3.2.2.1 The engineered safe feature actuation system Sensor Cabinet Power Supply Drawers shall be determined OPERABEL eeevep-&l" by visual inspection of the power supply drawer indicating lamps.

4.3.2.2.2 Verify the OPERABILITY of the Sensor Cabinet Power Supply auctioneering circuit ]

at 1 . o. A Ithe frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 3-23 Amendment No. 4-79, 282, 291

May+*3, +20.7-INSTRUMENTATION 3/4.3.3 MONITORING INSTRUMENTATION RADIATION MONITORING LIMITING CONDITION FOR OPERATION 3.3.3.1 The radiation monitoring instrumentation channels shown in Table 3.3-6 shall be OPERABLE with their alarm/trip setpoints within the specified limits.

APPLICABILITY: As shown in Table 3.3-6.

ACTION:

a. With a radiation monitoring channel alarm/trip setpoint exceeding the value shown in Table 3.3-6, adjust the setpoint to within the limit within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or declare the channel inoperable.

b. With the number of OPERABLE channels less than the number of MINIMUM I/

CHANNELS OPERABLE in Table 3.3-6, take the ACTION shown in Table 3.3-6.

The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS Srequire 4.3.3.1.1 Each radiation monitoring instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL CALIBRATION and CHANNEL FUNCTIONAL TEST operations during the MODES and at the frequencies shown in Table 4.3-3.

4.3.3.1.2 DELETED 4.3.3.1.3 Verify the response time of the control room isolation channel at lea .. e.ee-...

p mfeniths.

the frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 3-24 Amendment No. 5, 24-5, 282,2"4, 29-, -298

IReplace each marked through surveillance frequency in the Check, Calibration, and Functional Test columns with "SFCP" TABLE.

RADIATION MONITORING INSTRUMENWATlIoNAMAREILLANCE REQUIREMENTS H

0 CHANNEL MODES IN WHICH z~T1 CHANNEL CHANNEL FUNCTIONAL SURVEILLANCE INSTRUMENT CHECK CALIBRATION TEST REQUIRED

1. AREA MONITORS

a. Deleted

b. Control Room Isolation S R M ALL MODES

c. Containment High Range Is M 1, 2,3,&4

2. PROCESS MONITORS

a. Containment Atmosphere- Is R M 1, 2,3,&4 Particulate

b. Deleted

c. Noble Gas Effluent Sr R M 1,2,3, & 4 Monitor (high range)

> (Unit 2 Stack)

Calibration of the sensor with a radioactive source need only be performed on the lowest range. Higher ranges may be calibrated 0

0 electronically.

z0 C

C C

'I C

Sp.tlembi 25, 200 INSTRUMENTATION REMOTE SHUTDOWN INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.3.5 The remote shutdown monitoring instrumentation channels shown in Table 3.3-9 shall be OPERABLE with readouts displayed external to the control room.

APPLICABILITY: MODES 1, 2 and 3.

ACTION:

With the number of OPERABLE remote shutdown monitoring instrumentation channels less than required by Table 3.3-9, either:

a. Restore the inoperable channel to OPERABLE status within 7 days, or

b. Be in HOT SHUTDOWN within the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

SURVEILLANCE REQUIREMENTS

-reuired 4.3.3.5 Each remote shutdown monitoring instrumentation channel shall be demonstrated OPERABLE by performance of the CHANNEL CHECK and CHANNEL CALIBRATION operations at the frequencies shown in Table 4.3-6.

MILLSTONE - UNIT 2 3/4 3-28 Amendment No. 484 ý

[Replace each marked through surveillance frequency in the Check and Calibration columns with "SFCP" TABLE 4.3-REMOTE SHUTDOWN MONITORING INSTRUMENTA ON SURVEILL CE REQUIREMENTS 0z CHANNEL CHANNEL INSTRUMENT CHECK CALIBRATION

1. Wide Range Logarithmic Neutron Flux M R*

2 Reactor Trin Breaker Indication M N.A.

t'J

3. Reactor Cold Leg Temperature M R

4. Pressurizer Pressure

a. Low Range M R

b. High Range M R 0~

5. Pressurizer Level M R

6. Steam Generator Level M R

7. Steam Generator Pressure M R

Neutron detectors are excluded from the CHANNEL CALIBRATION.

0~

n z0 T.

7L

Marceh 16, 2006 INSTRUMENTATION ACCIDENT MONITORING LIMITING CONDITION FOR OPERATION 3.3.3.8 The accident monitoring instrumentation channels shown in Table 3.3-11 shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTION:

a. ACTIONS per Table 3.3-1 L. +-

SURVEILLANCE REQUIREMENTS reauired ?

4.3.3.8 Each accident monitoring instrumentation channel shall be demonstrated OPERABLE by performance of the CHANNEL CHECK and CHANNEL CALIBRATION operations at the frequencies shown in Table 4.3-7.

MILLSTONE - UNIT 2 3/4 3-31 Amendment No. 66, 4-5--, 28-2,294-

Replace each marked through surveillance frequency in the Check and Calibration columns with "SFCP" TABLE 4.3-7 ACCIDENT MONITORING INSTRUMENTATION S VEILLANCE R EMENTS CHANNEL CHANNEL INSTRUMENT CHECK CALIBRATION

1. Pressurizer Water Level M R

2. Auxiliary Feedwater Flow Rate M R

3. Reactor Coolant System Subcooled/Superheat Monitor M R

4. PORV Position Indicator M R 0 5. PORV Block Valve Position Indicator N.A. R

6. Safety Valve Position Indicator M R IV

7. Containment Pressure M R

8. Containment Water Level (Narrow Range) M R

9. Containment Water Level (Wide Range) M R

10. Core Exit Thermocouples M P*

11. Main Steam Line Radiation Monitor M R

12. Reactor Vessel Coolant Level M t*

Electronic calibration from the ICC cabinets only.

March 16, 2006 REACTOR COOLANT SYSTEM COOLANT LOOPS AND COOLANT CIRCULATION STARTUP AND POWER OPERATION LIMITING CONDITION FOR OPERATION 3.4.1.1 Two reactor coolant loops shall be OPERABLE and in operation.

APPLICABILITY: MODES 1 and 2. -I-ACTION:

With the requirements of the above specification not met, be in at least HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMENTS 4.4.1.1 The above required reactor coolant loops shall be verified to be in operation at kefte*

efteeper-12 heurs.

the frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 4-1 Amendment No. -50,69, 2-30, 249,2-94 Ressued by NRC L.,r,dated September- 27, 2006

june28, 2006 REACTOR COOLANT SYSTEM COOLANT LOOPS AND COOLANT CIRCULATION HOT STANDBY LIMITING CONDITION FOR OPERATION 3.4.1.2 Two reactor coolant loops shall be OPERABLE and one reactor coolant loop shall be in operation.

NOTE All reactor coolant pumps may not be in operation for up to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months per 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period provided:

~1

a. no operations are permitted that would cause introduction of coolant into the RCS with boron concentration less than required to meet the SDM of LCO 3.1.1.1; and

b. core outlet temperature is maintained at least 100 F below saturation temperature.

APPLICABILITY- MODE 3.

ACTION: a. With one reactor coolant loop inoperable, restore the required reactor coolant loop to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

b. With no reactor coolant loop OPERABLE or in operation, immediately suspend operations that would cause introduction of coolant into the RCS with boron concentration less than required to meet SDM of LCO 3.1.1.1 and immediately initiate corrective action to return one required reactor coolant

~1' loop to OPERABLE status and operation.

SURVEILLANCE REQUIREMENTS at the frequency specified in the Surveillance Frequency Control Program 4.4.1.2.1 Th1 rzquired reactor coolant pump, if not in operation, shall be determined to be OPERABLE onee per 7 days by verifying correct breaker alignment and indicated power available.

4.4.1.2.2 One reactor coolant loop shall be verified to be in operation at least oncc pcrt 12 h.ur..

4.4.1.2.3 Each steam generator secondary side water level sha e verified to be > 10% narrow range at @2t once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

MILLSTONE - UNIT 2

Se.pt$l*LmbL 14, 2000 REACTOR COOLANT SYSTEM COOLANT LOOPS AND COOLANT CIRCULATION HOT SHUTDOWN SURVEILLANCE REQUIREMENTS 4.4.1.3.1 The required pump, if not in operation, shall be determined OPERAB eIneeper--. 1/

4dys by verifying correct breaker alignment and indicated power available. 'I lat the frequency specified in the Surveillance Frequency Control Program 4.4.1.3.2 The required steam generator(s) shall be determined OPERABLE, by verifying the secondary side water level to be _ 10% narrow range at lcast oncc per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

4.4.1.3.3 One reactor coolant loop or shutdown c oling train shall be verified to be in operation [,

at least once per 12 hu.... A Fthe frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 4-1 c Amendment No. 69, 249

June 28, 2*09 REACTOR COOLANT SYSTEM COOLANT LOOPS AND COOLANT CIRCULATION COLD SHUTDOWN - REACTOR COOLANT SYSTEM LOOPS FILLED LIMITING CONDITION FOR OPERATION (continued)

APPLICABILITY: MODE 5 with Reactor Coolant System loops filled.

ACTION: a. With one shutdown cooling train inoperable and any steam generator secondary water level not within limits, immediately initiate action to either restore a second shutdown cooling train to OPERABLE status or restore steam generator secondary water levels to within limit.

b. With no shutdown cooling train OPERABLE or in operation, immediately suspend operations that would cause introduction of coolant into the RCS with boron concentration less than required to meet SDM of LCO 3.1.1.1 and immediately initiate action to restore one shutdown cooling train to OPERABLE status and operation.

SURVEILLANCE REQUIREMENTS lat the frequency specified in the Surveillance Frequency Control Program 4.4.1.4.1 The required shutdown cooling pum i t in operation, shall be determined OPERABLE enee-per---,days g correct breaker alignment and indicated power available.

4.4.1.4.2 The required steam generators shall be determined OPERABLE, by verifying the secondary side water level to be _>10% narrow range at least oncc pcr 12 hour-.

4.4.1.4.3 One shutdown cooling train shall be ve i ed to be in operationt leat ,eper 12 Ithe frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 4-1 e Amendment No. 2-49, 293-

September 14, 2000 REACTOR COOLANT SYSTEM COOLANT LOOPS AND COOLANT CIRCULATION COLD SHUTDOWN - REACTOR COOLANT SYSTEM LOOPS NOT FILLED SURVEILLANCE REQUIREMENTS

[at the frequency specified in the Surveillance Frequency Control Program I 4.4.1.5.1 The required shutdo wcooling pump, if not in operation, shall be determined OPERABLE onee-per 7 day7y verifying correct breaker alignment and indicated power available.

4.4.1.5.2 One shutdown cooling train shall be verified to be in operation at leastnee pc2 het-rs.

Ithe frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 4-1g Amendment No.-249-

Septembe 14, 2000 REACTOR COOLANT SYSTEM REACTOR COOLANT PUMPS /

COLD SHUTDOWN LIMITING CONDITION FOR OPERATION 3.4.1.6 A maximum of two reactor coolant pumps shall be OPERABLE.

APPLICABILITY: MODE 5 ACTION:

7 With more than two reactor coolant pumps OPERABLE, take immediate action to comply with Specification 3.4.1.6.

SURVEILLANCE REQUIREMENTS 4.4.1.6 Two reactor coolant pumps shall be demonstrated inoperable at least- nee-p&-

p hetr-s by verifying that the motor circuit breakers have been disconnerom their electrical power supply circuits.

Ithe frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 4-1h Amendment No. 8, 249

Marceh 26, 2013 REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS

[at the frequency specified in the Surveillance Frequency Control Program 4.4.3.1 In addition to the requirements of Specification 4.0.5, eac PORV shall be demonstrated OPERABLE:

a. OPeeRperf- :days by performance of a CHANNEL F CTIONAL TEST, excluding lve operation, and

b. Oep18--ý.-by performnance of aCHANNE CALIBRATION.

c. yeoperating by oIp e** the PORV throug one complete cycle of full travel a -ond io s representative of MODES 3 or 4.4.3.2 Each block valve h I e demonstrated OPERABLE ence per 92 dayS by operating the valve through one complete of full travel. This demonstration is not required if a PORV block valve is closed in accordan ith the ACTIONS of Specification 3.4.3.

lAt the frequency specified in the Surveillance Frequency Control Program[

MILLSTONE - UNIT 2 3/4 4-3a Amendment No. 66, 68, 4-5, 302, 344

ifflitafiy 30,200 REACTOR COOLANT SYSTEM PRESSURIZER LIMITING CONDITION FOR OPERATION 3.4.4 The pressurizer shall be OPERABLE with:

a. Pressurizer water level < 70%, and b. At least two groups of pressurizer heaters each having a capacity of at least 130 kW.

APPLICABILITY: MODES 1, 2 and 3.

ACTION:

a. With only one group of pressurizer heaters OPERABLE, restore at least two groups to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in HOT SHUTDOWN within the following 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

b. With the pressurizer otherwise inoperable, be in at least HOT STANDBY with the reactor trip breakers open within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMENTS 4.4.4.1 The pressurizer water level shall be determined to be within its limits t lea.steee per-12 hetrs.

4.4.4.2 Verify at least two groups of pressurizer heaters ea ave a capacity of at least 130 kW at ..... n.er. 92 days.

Fthe frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 4-4 Amendment No. 66, 74, 9-7, 4-30, 24-9, 264-, 296

Septeimb*r 30, 2098 REACTOR COOLANT SYSTEM 3/4.4.6 REACTOR COOLANT SYSTEM LEAKAGE LEAKAGE DETECTION SYSTEMS LIMITING CONDITION FOR OPERATION ACTION: (Continued)

2. Appropriate grab samples of the containment atmosphere are obtained and analyzed for particulate radioactivity within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and at least once per 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months thereafter, and

3. A Reactor Coolant System water inventory balance is performed within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and at least once per 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months thereafter.

Otherwise, be in COLD SHUTDOWN within the next 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

SURVEILLANCE REQUIREMENTS 4.4.6.1 The leakage detection systems shall be demonstrated OPERABLE by:

a. Containment atmosphere particulate monitoring system-performance of CHANNEL CHECK, CHANNEL CALIBRATION and CHANNEL FUNCTIONAL TEST at the frequencies specified in Table 4.3-3, and

b. Containment sump level monitoring system-performance of CHANNEL CALIBRATION TEST at least ene. per- 18 meath..

Ithe frequency specified in the Surveillance Frequency Control Program I MILLSTONE - UNIT 2 3/4 4-8a Amendment 306--

May 3 1, fO REACTOR COOLANT SYSTEM REACTOR COOLANT SYSTEM OPERATIONAL LEAKAGE LIMITING CONDITION FOR OPERATION 3.4.6.2 Reactor Coolant System Operational LEAKAGE shall be limited to:

a. No PRESSURE BOUNDARY LEAKAGE,

b. 1 GPM UNIDENTIFIED LEAKAGE,

c. 75 GPD primary to secondary LEAKAGE through any one steam generator, and

d. 10 GPM IDENTIFIED LEAKAGE.

APPLICABILITY: MODES 1, 2, 3 and 4.

ACTION:

a. With any RCS operational LEAKAGE not within limits for reasons other than PRESSURE BOUNDARY LEAKAGE or primary to secondary LEAKAGE, reduce LEAKAGE to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

b. With ACTION and associated completion time of ACTION a. not met, or PRESSURE BOUNDARY LEAKAGE exists, or primary to secondary LEAKAGE not within limits, be in HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and be in COLD SHUTDOWN within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

SURVEILLANCE REQUIREMENTS 4.4.6.2.1

- - - - - - - - ----------- NOTES- - ---------------

1. Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation.

2. Not applicable to primary to secondary LEAKAGE.

Verify RCS operational LEAKAGE is within limits by performance of RCS water inventory balance at .. r "e t" Ithe frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 4-9 Amendment No. 2-5, 7, 82, 8-5, 4-0+,

4-24,8, 24-19 , 22-8,-299-

REACTOR COOLANT SYSTEM REACTOR COOLANT SYSTEM OPERATIONAL LEAKAGE SURVEILLANCE REQUIREMENTS (Continued) 4.4.6.2.2

NOTE -.-.-.-.-------------------- --

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation.

Verify primary to secondary LEAKAGE is < 75 gallons per day through any one SG at least-eee pert hours. f c Ithe frequency specified in the Surveillance Frequency Control Proaram MILLSTONE - UNIT 2 3/4 4-10 Amendment No. 266,294

October 27, 2008 REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS 4.4.8.1 Verify the specific activity of the primary coolant < 1100 [iCi/gram DOSE /

EQUIVALENT XE-133 -*ccper 7 days.

4.4.8.2 Verify the specific activity the primary coolant _<1.0 jiCi/gram DOSE EQUIVALENT 1-13 1 -Y.,-*. and between 2 and 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after a THERMAL POWER c nge o Ž_15% RATED THERMAL POWER within a one /

hour period.

lat the frequency specified in the Surveillance Frequency Control Program I

Surveillance only required to be performed for MODE 1 operation, consistent with the provisions of Specification 4.0.1.

MILLSTONE - UNIT 2 3/4 4-14 Amendment No. 4-1-5, 30

Ja.*,t.ary 2,00.

REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS 4.4.9.1

a. The Reactor Coolant System temperature and pressure shall be determined to be within the limits atper 30 mintce during system heatup, cooldown, and inservice leak and rostatic testing operations.

b. DELETED , the frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 4-18 Amendment No. 8,2,2

March.30-200-REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENT 4.4.9.3.1 Each PORV shall be demonstrated OPERABLE by:

a. Performance of a CHANNEL FUNCTIONAL TEST on the PORV actuation channel, but excluding valve operation, within 31 days prior to entering a condition in which the PORV is required OPERABLE and at least @-ee pe, 34-dys thereafter when the PORV is required OPERABLE.

b. Performance of a CHANNEL CALIBRATION on the RV actuation channel at Iant

.... c' l8nths.

c. Verifying he PORV block valve is open atst- when the PORV is being sed for overpressure protectio.

d. Testing* accordance with the inse ice est requirements of Specification 4.0.5.

4.4.9.3.2 Verifyno ore than the maximum o ed number of charging pumps are capable of injecting into the RC at max 4.4.9.3.3 Verify no re than the ma n allowed number of HPSI pumps are capable of injecting into the R St lSt 4.4.9.3.4 Verify t r quired R vent is open at lea1t ,ne, p.r, 31 *ays when the vent pathway is provided by yen a ye(s)tl*s(are) locke e led, or otherwise secured in the open position, otherwise, verify t ent p *ay-e r u.

the frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 4-2 lb Amendment No. 1O, 1-4-7, 1-8-, 2-g, 227, 243-

EMERGENCY CORE COOLING SYSTEMS SAFETY INJECTION TANKS (Continued)

SURVEILLANCE REQUIREMENTS 4.5.1 Each SIT shall be demonstrated OPERABLE:

a. Verify each SIT isolation valve is fully open at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .*(1)

b. Verify borated water volume in each SIT is _>080 cubic feet and _<1190 cubic feet at e**(2)

c. Verify itrogen cover-pressure in each SIT s _ 200 psig and _<250 psig at least p-- I ho rs.*** (3)Z

d. Verify boron ncentration in each SIT i Ž 1720 ppm e 6 and once within hours after each solu on volume i rease* %of tank volume****( 4 ) tha is not the result of ddition fro the eling water storage tank.

(I) If one SIT is inoperable, except as a result of boron concentration not within limits or inoperable level or pressure instrumentation, surveillance is not applicable to the affected SIT.

- (2) If one SIT is inoperable due solely to inoperable water level instrumentation, surveillance is not applicable to the affected SIT.

- - (3) If one SIT is inoperable due solely to inoperable pressure instrumentation, surveillance is not applicable to affected SIT.

- - - (4)Only required to be performed for affected SIT.

MILLSTONE - UNIT 2 3/4 5-2 Amendment No. 45,-202, 224, -68

September 9,2004 EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS 4.5.2 Each ECCS subsystem shall be demonstrated OPERABLE:

a. At) by verifying each Emergency Core Cooling System ma ual, power operated, and automatic valve in the flow path servicing safety relat d equipment, that is not locked, sealed, or otherwise secured in position, is in the c ect position. /

b. iee*per- 314dys by verifying that the following valves are in the indicated pos Io ,ith power to the valve operator removed:

Valve Function Valve Position 2-SI-3i Shutdown Cooling Open*

Flow Control 2-SI-659 SRAS Recirc. Open**

2-SI-660 SRAS Recirc. Open**

/

Pinne( cked at preset throttle open position.

- To be nior to recirculation following LOCA.

c. By verifying the de el ped head of each high pressure safety injection pump at the flow test point is gre te than or equal to the required developed head when tested pursuant to Specificato 4.0.5.

d. By verifying the develo e head of each low pressure safety injection pump at the flow test point is greater n or equal to the required developed head when tested pursuant to Specification . .5.

e. By verifying the delivered of each charging pump at the required discharge

/

pressure is greater than or eq to the required flow when tested pursuant to /

Specification 4.0.5.

f. At pr 18 months by ifying each Emergency Core Cooling System auto ic valve in the flow path t is not locked, sealed, or otherwise secured in position, ates to the correct po tion on an actual or simulated actuation signal.

g. At, . one . per

. by veri fng each high pressure safety injection pump I

/

and lo ssure safety iection pu starts automatically on an actual or simulated actua signal.

MILLS TONE - UNIT 2 3/4 - Amendment No. 52, 4-59, 236,-8 Ithe frequency specified in the Surveillance Frequency Control Program

September- 18, 2007 EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

h. At e aa 8 m.n-an

p. by verifying each low pressure safety injection pum p sto automatically on an actual or simulated actuation signal.

By ven' ing the correct position of each electrical and/or mechanical position stop for7each ection valve in Table 4.5-1:

1. Withi 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after completion of valve operations.

.At

, 1 - b y v e r i f y i n g th ro u g h v is ua l in sp e c ti on o f t h e con ent su tha each Emergency Core Cooling System subsystem suction inlet is n restricte by ebris and the suction inlet strainers show no evidence of le structural di ess or no al corrosion.

k. At verifying the Shutdown Cooling System open permis interlock p ent t Shutdown Cooling System inlet isolation valves from being o d with a c or simulated Reactor Coolant System pressure signal of 300_> psia.

Ithe frequency specified in the Surveillance Frequency Control Program I MILLSTONE - UNIT 2 3/4 5-5 Amendment No. 7, 45, -52,64-,-4041, 4-59, 464,24-7, 244-5, 2-3, 283, EMERGENCY CORE COOLING SYSTEMS REFUELING WATER STORAGE TANK LIMITING CONDITION FOR OPERATION 3.5.4 The refueling water storage tank shall be OPERABLE with:

a. A minimum contained volume of 370,000 gallons of borated water,

b. A minimum boron concentration of 1720 ppm,

c. A minimum water temperature of 50'F when in MODES 1 and 2, and

d. A minimum water temperature of 35'F when in MODES 3 and 4.

APPLICABILITY: MODES 1, 2, 3 and 4.

ACTION:

With the refueling water storage tank inoperable, restore tank to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or be in COLD SHUTDOWN within the next 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SURVEILLANCE REQUIREMENTS 4.5.4 The RWST shall be demonstrated OPERABLE:

a. At per 7 days by:

1. Verifying the water level in the tank, and

2. Verifying the boron concentration of the water.

b. When in ODES 3 and 4, at lcast cncz pcr 21 hours2.430556e-4 days 0.00583 hours 3.472222e-5 weeks 7.9905e-6 months by verifying the RWST temperatu e is _>35'F whe e RWST ambient air temperature is < 35°F.

c. When in M DES 1 and , a least onee per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months by verifying the RWST temperature i 50'F h he RWST ambient air temperature is < 50'F.

the frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 5-8

JItt.ry 3, ,206 EMERGENCY CORE COOLING SYSTEMS TRISODIUM PHOSPHATE (TSP)

LIMITING CONDITION FOR OPERATION 3.5.5 The TSP baskets shall contain Ž282 ft3 of active TSP.

APPLICABILITY: MODES 1, 2, and 3 ACTION:

With the quantity of TSP less than required, restore the TSP quantity within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , or be in MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 4 within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMENTS 4.5.5.1 Verify that the TSP baskets contain Ž>282 ft3 of TSP at least ncc per 18 months.

4.5.5.2 Verify that a sample from the TSP baskets provides a equate pH adjustment of borated water at I- on..

[the frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 5-9 Amendment No. 2-P-t,-490-

Mareh 16, 2 06 3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT CONTAINMENT INTEGRITY LIMITING CONDITION FOR OPERATION 3.6.1.1 Primary CONTAINMENT INTEGRITY shall be maintained.

APPLICABILITY: MODES 1, 2, 3 and 4.

ACTION:

Without primary CONTAINMENT INTEGRITY, restore CONTAINMENT INTEGRITY within one hour or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the next 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SURVEILLANCE REQUIREMENTS 4.6.1.1 Primary CONTAINMENT INTEGRITY shall be demonstrated:

a. At ka,,t oI.L% pJ, 31 days by verifying that all penetrations"l) not capable of being clo! d by OPERABLE containment automatic isolation valves(2) and required to be dlosed during accident conditions are closed by valves, blind flanges, or deactiva d automatic valves secured in their positions,(3 ) except for valves that are open u der administrative control as permitted by Specification 3.6.3.1.

b. A ---- by verifying the equipment hatch is closed and sealed.

C. By venr ng the c tainment air lock is in compliance with the requirements of Specificati 3.6.1.3.

d. After each closing a pe etration subject to type B testing (except the containment air lock), op ed following a Type A or B test, by leak rate testing in accordance with the C tai ent Leakage Rate Testing Program.

e. By verifying Containment struc 1integrity in accordance with the Containment Tendon Surveillance Program.

Ithe frequency specified in the Surveillance Frequency Control Program (1) Except valves, blind flanges, and deactivated automatic valves which are located inside the containment and are locked, sealed, or otherwise secured in the closed position.

These penetrations shall be verified closed prior to entering MODE 4 from MODE 5, if not performed within the previous 92 days.

(2) In MODE 4, the requirement for an OPERABLE containment automatic isolation valve system is satisfied by use of the containment isolation trip pushbuttons (3) Isolation devices in high radiation areas may be verified by use of administrative means.

MILLSTONE - UNIT 2 3/4 6-1 Amendment No. 2-5, 9-5, 20-3, 2--0, 2--4, 2-7-, 29-17

iutme 7,200P CONTAINMENT SYSTEMS CONTAINMENT AIR LOCKS SURVEILLANCE REQUIREMENTS 4.6.1.3.1 Each containment air lock shall be demonstrated OPERABLE in accordance with the Containment Leakage Rate Testing Program. Containment air lock leakage test results shall be evaluated against the leakage limits of Technical Specification 3.6.1.2. (An inoperable air lock door does not invalidate the previous successful performance of the overall air lock leakage test).

4.6.1.3.2 Each containment air lock shall be demonstrated OPERABLE last

. nce p

-months by verifying that only one door in each air lock a time.

[the frequency specified in the Surveillance Frequency Control Proqram[

MILLSTONE - UNIT 2 3/4 6-6a Amendment No. 4-54, 203, 26 Oetaber-27, 1997 CONTAINMENT SYSTEMS INTERNAL PRESSURE LIMITING CONDITION FOR OPERATION 3.6.1.4 Primary containment internal pressure shall be maintained between -12 inches Water Gauge and +1.0 PSIG. 4 APPLICABILITY: MODES 1, 2, 3 and 4.

ACTION:

With the containment internal pressure in excess of or below the limits above, restore the internal pressure to within the limits within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or be in HOT STANDBY within the next 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ; go to COLD SHUTDOWN within the next 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

SURVEILLANCE REQUIREMENTS 4.6.1.4 The primary containment internal pressure shall be determined to within the limits at least oil, per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

[the frequency specified in the Surveillance Frequency Control Program]

MILLSTONE - UNIT 2 3/4 6-8 Amendment No. 209-

A~ .... ~ 2 1, 19198*'*

CONTAINMENT SYSTEMS AIR TEMPERATURE LIMITING CONDITION FOR OPERATION 3.6.1.5 Primary containment average air temperature shall not exceed 120'F.

APPLICABILITY: MODES 1, 2, 3 and 4.

ACTION:

With the containment average air temperature > 120'F, reduce the average air temperature to within the limit within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months , or be in COLD SHUTDOWN within the next 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

SURVEILLANCE REQUIREMENTS 4.6.1.5 The primary containment average air temperature shall be determined to be < 120°F a least per 21fnqe hours..

Ithe frequency specified in the Surveillance Frequency Control Proqram MILLSTONE - UNIT 2 3/4 6-9 Amendment No. 2-t Mari, 16, 2-0.6 CONTAINMENT SYSTEMS 3/4.6.2 DEPRESSURIZATION AND COOLING SYSTEMS CONTAINMENT SPRAY AND COOLING SYSTEMS LIMITING CONDITION FOR OPERATION 3.6.2.1 Two containment spray trains and two containment cooling trains, with each cooling train consisting of two containment air recirculation and cooling units, shall be OPERABLE.

APPLICABILITY: MODES 1, 2 and 3*

ACTION: I?

Inoperable Equipment Required ACTION

a. One containment a. 1 Restore the inoperable containment spray train to spray train OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and reduce pressurizer pressure to less than 1750 psia within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

b. One containment b. 1 Restore the inoperable containment cooling train to cooling train OPERABLE status within 7 days or be in HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

c. One containment c. 1 Restore the inoperable containment spray train or the spray train inoperable containment cooling train to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in HOT SHUTDOWN within the next AND 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

One containment cooling train

d. Two containment d. 1 Restore at least one inoperable containment cooling train to cooling trains OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

e. All other e. 1 Enter LCO 3.0.3 immediately.

combinations SURVEILLANCE REQUIREMENTS 4.6.2.1.1 Each containment spray train shall be demonstrated OPERABLE:

a. At ea*ti once p.cr _31 dayýsyverifying each containment spray manual, power operated, and automatic valvente spray train flow path, that is not locked, sealed, or otherwise secured in posift0i, is in the correct position.

Ithe frequency specified in the Surveillance Frequency Control Program]

The Containment Spray System is not required to be OPERABLE in MODE 3 if pressurizer pressure is < 1750 psia.

MILLSTONE - UNIT 2 3/4 6-12 Amendment No. 2-4-5, 22-8, 2-36, 283, 294

MtVchll 31f, 2008 CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

Ithe frequency specified in the Surveillance Frequency Control Proqramr

b. By verifying the developed head of each conta ent spray pump at the flow test point is greater than or equal to th *r ".eloped head when tested pursuant to Specification 4.0.5--/

c. At -. by b-lo vpe erif each automatic containment spray valve in the flow path th *snot locked, d, or otherwise secured in position, actuates to t orrect position actual or simulated actuation signal.

d. At oa* * *,- erifying et each containment spray pump starts automatically on an ac I mulated actuation signal.

e. By verifying each pr cause nozzle bl cka e.

zzle is unobstructed following activities that could 1f 4.6.2.1 .2 Each contai ent *rr irculation and cooling unit shall be demonstrated OPERAABLE:

a. At E)--by operating each containment air recirculation and coolin uni n slow speed for > 15 minutes.

b. At per- d by verifying each containment air recirculation and cooli unit cooling water flow rate is > 500 gpm.

c. At 'ast once per 18 months by verifying each containment air recirculation and cooling unit starts automatically on an actual or simulated actuation signal.

MILLSTONE - UNIT 2 3/4 6-13 Amendment No. 24-5, 283, 303-

CONTAINMENT SYSTEMS 3/4.6.3 CONTAINMENT ISOLATION VALVES LIMITING CONDITION FOR OPERATION 3.6.3.1 Each containment isolation valve shall be OPERABLE.(') (2)

APPLICABILITY: MODES 1, 2, 3 and 4.

ACTION:

With one or more of the isolation valve(s) inoperable, either:

a. Restore the inoperable valve(s) to OPERABLE status within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , or

b. Isolate the affected penetration(s) within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months by use of a deactivated automatic valve(s) secured in the isolation position(s), or

c. Isolate the affected penetration(s) within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months by use of a closed manual valve(s) or blind flange(s); or

d. Isolate the affected penetration that has only one containment isolation valve and a closed system within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months by use of at least one closed and deactivated automatic valve, closed manual valve, or blind flange; or

e. Be in COLD SHUTDOWN within the next 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

SURVEILLANCE REQUIREMENTS 4.6.3.1 Each containment isolation valve shall be demonstrated OPERABLE:

a. By verifying the isolation time of each power operated automatic containment isolation valve when tested pursuant to Specification 4.0.5.

b. At least eonce per- 18 mcnths-by verifying each automatic containment isolation valve that is not locked, sealed, orý se secured in position, actuates to the isolation position on an actual or simulated ac signal.

the frequency specified in the Surveillance Frequency Control Program (1) Containment isolation valves may be opened on an intermittent basis under administrative controls. 4 (2) The provisions of this Specification in MODES 1, 2 and 3, are not applicable for main steam line isolation valves. However, provisions of Specification 3.7.1.5 are applicable for main steam line isolation valves.

MILLSTONE - UNIT 2 3/4 6-15 Amendment No. 6, 24-0, 2-7-,-7-8

Jtmec 16, 1998 CONTAINMENT SYSTEMS CONTAINMENT VENTILATION SYSTEM LIMITING CONDITION FOR OPERATION 3.6.3.2 The containment purge supply and exhaust isolation valves shall be sealed closed. A' APPLICABILITY: MODES 1, 2, 3 and 4.

ACTION:

With one containment purge supply and/or one exhaust isolation valve open, close the open valve(s) within one hour or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SURVEILLANCE REQUIREMENTS 4.6.3.2 The containment purge supply and exhaust isolation valves shall be determined sealed closed at least . 31day-.

the frequency specified in the Surveillance Frequency Control Proqram MILLSTONE - UNIT 2 3/4 6-19 Amendment No. 64,2+6-

CONTAINMENT SYSTEMS POST-INCIDENT RECIRCULATION SYSTEMS LIMITING CONDITION FOR OPERATION 3.6.4.4 Two separate and independent post-incident recirculation systems shall be OPERABLE.

APPLICABILITY: MODES 1 and 2.

ACTION:

With one post-incident recirculation system inoperable, restore the inoperable system to OPERABLE status within 30 days or be in HOT STANDBY within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

SURVEILLANCE REQUIREMENTS Ithe frequency specified in the Surveillance Frequency Control Program ,

4.6.4.4 Each post-incident recirculation system shall be demonstrated OPERABLE a- leasA nce per-92 days on a STAGGE-*DF TE=ST_- BASIS by:

a. Verifying that the system can be started on operator action in the control room, and

b. Verifying that the system operates for at least 15 minutes.

MILLSTONE - UNIT 2 3/4 6-24

Septefmber- 30, 1997 CONTAINMENT SYSTEMS 3-/4.6.5 SECONDARY CONTAINMENT ENCLOSURE BUILDING FILTRATION SYSTEM LIMITING CONDITION FOR OPERATION 3.6.5.1 Two separate and independent Enclosure Building Filtration Trains shall be OPERABLE.

APPLICABILITY: MODES 1, 2, 3 and 4.

ACTION:

With one Enclosure Building Filtration Train inoperable, restore the inoperable train to OPERABLE status within 7 days or be in COLD SHUTDOWN within the next 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . '

SURVEILLANCE REQUIREMENTS

[the frequency specified in the Surveillance Frequency Control Program 4.6.5.1 Each Enclosure Building Filtrat s e demonstrated OPERABLE:

a. At ,Ts "RED TEST B by initiating, from the control room, flib ough the HEPA filter and charcoal absorber train and verifyin ýe train operates for at least 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months with the heaters on.

b. At least en.. per-18 m ,nths or (1) after any structural maintenance on the HEPA filter or charcoal absorber housings, or (2) following painting, fire or chemical release in any ventilation zone communicating with the train by:

MILLSTONE - UNIT 2 3/4 6-25 Amendment No. 20ft

March i 0, 1999 CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

1. Verifying that the cleanup train satisfies the in-place testing acceptance criteria and uses the test procedures of Regulatory Positions C.5.a, C.5.c and C.5.d of Regulatory Guide 1.52, Revision 2, March 1978, and the train flow rate is 9000 cfm +/- 10%.

2. Verifying within 31 days after removal that a laboratory analysis of a representative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978.*

3. Verifying a train flow rate of 9000 cfm + 10% during train operation when tested in accordance with ANSI N510-1975.

c. After every 720 hours0.00833 days 0.2 hours 0.00119 weeks 2.7396e-4 months of charcoal adsorber operation by verifying within 31 days after removal that a laboratory analysis of a representative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978.*

d. At las oiicc per 18 mon.ths by:

1. Verifying that the pressure drop across the combined HEPA filters and charcoal adsorber banks is _<2.6 inches Water Gauge while operating the ain at a flow rate of 9000 cfm +/- 10%.

2. Vifying that the train starts on an Enclosure Building Filtration Actuation Sig al (EBFAS).

e. After each co plete or partial replacement of a HEPA filter bank by verifying that the HEPA filte banks remove greater than or equal to 99% of the DOP when they are tested in-pl e in accordance with ANSI N510-1975 while operating the train at a flow rate of 000 cfm + 10%.

Ithe frequency specified in the Surveillance Frequency Control Program ASTM D3803-89 shall be used in place of ANSI N509-1976 as referenced in table 2 of Regulatory Guide 1.52. The laboratory test of charcoal should be conducted at a temperature of 30'C and a relative humidity of 95% within the tolerances specified by ASTM D3803-89.

Additionally, the charcoal sample shall have a removal efficiency of _ 95%.

MILLSTONE - UNIT 2 3/4 6-26 Amendment No. 25, 72, 4-7-5, 2-8, 2-28

September 30, 1997 CONTAINMENT SYSTEMS ENCLOSURE BUILDING -"

LIMITING CONDITION FOR OPERATION 3.6.5.2 The Enclosure Building shall be OPERABLE.

APPLICABILITY: MODES 1, 2, 3 and 4.

ACTION:

With the Enclosure Building inoperable, restore the Enclosure Building to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or be in COLD SHUTDOWN within the next 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . t SURVEILLANCE REQUIREMENTS 4.6.5.2.1 OPERABILITY of the Enclosure Building shall be demonstrated at least-enee pet-31 days by verifying that each access opening is closed except when the access o ing is being used for normal transit entry and exit.

'p 4.6.5.2.2. At lcast encc pcr 18 mcnth, rify each Enclosure Buildin iltration Train produces a negative pressure of greater than or equa'o 0.25 inches W.G. in th nclosure Building Filtration Region within 1 minute after an En sure Building Filtr ion Actuation Signal.

4/

-I the frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 6-28 Amendment No. 248

Jj~fiif-Th34O,20 PLANT SYSTEMS AUXILIARY FEEDWATER PUMPS LIMITING CONDITION FOR OPERATION I ACTION: (Continued)

Inoperable Equipment Required ACTION

e. Three auxiliary feedwater pumps in MODE 1, 2, or 3.

e.

- - - - ---- NOTE -------

/4, 1~

LCO 3.0.3 and all other LCO required ACTIONS requiring MODE changes are suspended until one AFW pump is restored to OPERABLE status.

Immediately initiate ACTION to restore one auxiliary feedwater pump to OPERABLE status.

SURVEILLANCE REQUIREMENTS 4.7.1.2 Each auxiliary feedwater pump shall be demonstrated OPERABLE:

a. At lest,unoie yri 31, daya by verifying each auxiliary feedwater manual, power op ted, and automatic valve in each water flow path and in each steam supply flow p th to the steam turbine driven pump, that is not locked, sealed, or otherwise secured i position, is in the correct position.

"in

b. By verifying e developed head of each auxiliary feedwater pump at the flow test point is greater an or equal to the required developed head when tested pursuant to Specification 4. 5. (Not required to be performed for the steam turbine driven auxiliary feedwater p mp until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after reaching 800 psig in the steam generators. The provis ns of Specification 4.0.4 are not applicable to the steam turbine driven auxiliary fdwater pump for entry into MODE 3.)

Ithe frequency specified in the Surveillance Frequency Control Program]

MILLSTONE - UNIT 2 3/4 7-5 Amendment No. -23,6-3, 283, 29-7

PLANT SYSTEMS AUXILIARY FEEDWATER PUMPS SURVEILLANCE REQUIREMENTS (Continued)

c. At ast oncc per 18 mOnths by verifying each auxiliary feedwater automatic valve tha s not locked, sealed, or otherwise secured in position, actuates to the correct positi as designed, on an actual or simulated actuation signal.

d. At least o- 11pr- 18 mont~h by verifying each auxiliary feedwater pump starts aut atical as designed, on an actual or simulated actuation signal.

e. By verifyi th roper alignment of the required auxiliary feedwater flow paths by verifying w om the condensate storage tank to each steam generator prior to entering MO whenever the unit has been in MODE 5, MODE 6, or defueled for a cum *ve period of greater than 30 days.

[the frequency specified in the Surveillance Frequency Control ProgramI MILLSTONE - UNIT 2 3/4 7-5a Amendment No. 29 4'

DIJe rllll 3 1,i 998 PLANT SYSTEMS CONDENSATE STORAGE TANK LIMITING CONDITION FOR OPERATION 3.7.1.3 The condensate storage tank shall be OPERABLE with a minimum contained volume of 165,000 gallons. -1 APPLICABILITY: MODES 1, 2 and 3.

ACTION:

With less than 165,000 gallons of water in the condensate storage tank, within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months either:

a. Restore the water volume to within the limit or be in HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , or

b. Demonstrate the OPERABILITY of the fire water system as a backup supply to the auxiliary feedwater pumps and restore the condensate storage tank water volume to within its limits within 7 days or be in HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

SURVEILLANCE REQUIREMENTS 4.7.1.3 The condensate storage tank shall be demonstrated OPERABLE least onte-pere 1 hours1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months ' by verifying the water level.

Ithe frequency specified in the Surveillance Frequency Control ProgramI MILLSTONE - UNIT 2 3/4 7-6 Amendment No. 2 Auut 2, 198 TABLE 4.7-2 SECONDARY COOLANT SYSTEM SPECIFIC ACTIVITY SAMPLE AND ANALYSIS PROGAM TYPE OF MEASUREMENT MINIMUM AND ANALYSIS FREQUENCY

1. Gross Activity Determination 3 times.pe.r 7days with a maximum ime of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months between samples. -I-

2. Isotopic Analysis for DOSE a) 1 per 31 days, whenever the EQUIVALENT 1-131 gross activity determination Concentration indicates iodine concentrations greater than 10% of the allowable limit b) whenever the gross activity determination indicates iodine concentrations below 10% of the allowable limit.

/

lAt the frequency specified in the Surveillance Frequency Control Program

/

MILLSTONE - UNIT 2 3/4 7-8 Amendment No. 7, 4-04

MarLI 16, 2006 PLANT SYSTEMS MAIN FEEDWATER ISOLATION COMPONENTS (MFICs)

LIMITING CONDITION FOR OPERATION (Continued)

b. With two or more of the feedwater isolation components inoperable in the same flow path, either:

1. Restore the inoperable component(s) to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months until ACTION 'a' applies, or /4

2. Isolate the affected flow path within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months , and verify that the inoperable feedwater isolation components are closed or isolated/secured once per 7 days, or

3. Be in HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

SURVEILLANCE REQUIREMENTS the frequency specified in the Surveillance Frequency Control Program 4.7.1.6 Each/feedwater isolation valve/feedwater pump trip circuitry shall be demonstrated OPERABLE at',*t cn-c pcr 18 ,"'nth, by:

a. Verifying that on 'A' main steam isolation test signal, each isolation valve actuates to its isolation position, and

b. Verifying that on 'B' main steam isolation test signal, each isolation valve actuates to its isolation position, and

c. Verifying that on 'A' main steam isolation test signal, each feedwater pump trip circuit actuates, and

d. Verifying that on 'B' main steam isolation test signal, each feedwater pump trip circuit actuates.

MILLSTONE - UNIT 2 3/4 7-9b Amendment No. "8, 2-94 Rei.*ued by NRC-L ,eftzr dated September 27, 2006

Aug.st- 1,1N999 PLANT SYSTEMS ATMOSPHERIC DUMP VALVES LIMITING CONDITION FOR OPERATION 3.7.1.7 Each atmospheric dump valve line shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTION:

a. With one atmospheric dump valve line inoperable, restore the inoperable line to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 4 within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

b. With more than one atmospheric dump valve line inoperable, restore one inoperable line to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or be in MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 4 within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

SURVEILLANCE REQUIREMENTS 4.7.1.7 Verify the OPERABILITY of each atmospheric dump valve line by local manual operation of each valve in the flowpath through one complete cycle of operation at leastea.r.@ we-f8 ieths. Ft

[the frequency specified in the Surveillance Frequency Control ProgramI MILLSTONE - UNIT 2 3/4 7-9c Amendment No. 272-3, 2 PLANT SYSTEMS STEAM GENERATOR BLOWDOWN ISOLATION VALVES LIMITING CONDITION FOR OPERATION 3.7.1.8 Each steam generator blowdown isolation valve shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3 ACTION:

With one or more steam generator blowdown isolation valves inoperable, either:

a. Restore the inoperable valve(s) to OPERABLE status within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ; or

b. Isolate the affected steam generator blowdown line within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ; or

c. Be in MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 4 within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMENTS 4.7.1.8 Verify the closure time of each steam generator blowdown isolation valve is _<10 seconds on an actual or simulated closure signal at k,...... pff 18 months Ithe frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 7-9d Amendment No. 22 FbmUary 13, 2003 PLANT SYSTEMS 3/4.7.3 REACTOR BUILDING CLOSED COOLING WATER SYSTEM LIMITING CONDITION FOR OPERATION 3.7.3.1 Two reactor building closed cooling water loops shall be OPERABLE. A-APPLICABILITY: MODES 1, 2, 3 and 4.

ACTION:

With one reactor building closed cooling water loop inoperable, restore the inoperable loop to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in COLD SHUTDOWN within the next 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . 4-SURVEILLANCE REQUIREMENTS 4.7.3.1 Each reactor building closed cooling water loop shall be demonstrated OPERABLE:

a. At by verifying each reactor building closed cooling water ma al, power operated, and automatic valve in the flow path servicing safety relate equipment, that is not locked, sealed, or otherwise secured in position, is in the co ct position.

b. Aer1 ,nth by verifying each reactor building closed cooling watee tom tic valve in the flow path that is not locked, sealed, or otherwise secured i posi ion, actuates to the correct position on an actual or simulated actuation s a .

C. AteIerAltnAnt.sby verifying each reactor building closed cooling water pu sa matically on an actual or simulated actuation signal.

Ithe frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 7-11 Amendment No. 2-36, 23

Fehslar-y'!3,2003 PLANT SYSTEMS 33/4.7.4 SERVICE WATER SYSTEM LIMITING CONDITION FOR OPERATION 3.7.4.1 Two service water loops shall be OPERABLE.

APPLICABILITY: MODES 1, 2, 3 and 4.

ACTION:

With one service water loop inoperable, restore the inoperable loop to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in COLD SHUTDOWN within the next 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . X SURVEILLANCE REQUIREMENTS 4.7.4.1 Each service water loop shall be demonstrated OPERABLE:

a. At per 31 days by verifying each service water manual, power operated, I an tomatic valve in the flow path servicing safety related equipment, that is not /

locked,"ealed, or otherwise secured in position, is in the correct position.

b. I.me..th. by verifying each service water automatic valve in the t locked, sealed, or otherwise secured in position, actuates to

,on an actual or simulated actuation signal.

/

C. by verifying each service water pump starts r simulated actuation signal.

Ithe frequency specified in the Surveillance Frequency Control Program I MILLSTONE - UNIT 2 3/4 7-12 Amendment No. 4-73, 2-36, 2-7-3

MaIlrchL 10, i 999 PLANT SYSTEMS SURVEILLANCE REQUIREMENTS the frequency specified in the Surveillance Frequency Control Program 4.7.6.1 Each Control Room Emergency ConrolRom Emrgency Ventilation Ventilation Trai Ta shall be demonstrated OPERABLE: 4-

a. At v that the control room air temperature is <

100"F.

b. At BA byTEST by initiating from the control room, fl through the HEPA filters and charcoal absorber train and verifyin e train operates for at least 15 minutes.

c. At or (1) after any structural maintenance on the HEPA filter or charcoal adsorber housings, or (2) following painting, fire or chemical release in any ventilation zone communicating with the train by:

1. Verifying that the cleanup train satisfies the in-place testing acceptance I

criteria and uses the test procedures of Regulatory Positions C.5.a, C.5.c and C.5.d of Regulatory Guide 1.52, Revision 2, March 1978, and the train flow rate is 2500 cfm +/- 10%. --

2. Verifying within 31 days after removal that a laboratory analysis of a representative carbon sample obtained in accor-dance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revi-sion 2, March 1978.* The carbon sample shall have a removal efficiency of> 95 percent.

3. Verifying a train flow rate of 2500 cfm + 10% during train operation when tested in accordance with ANSI N510-1975.

d. After every 720 hours0.00833 days 0.2 hours 0.00119 weeks 2.7396e-4 months of charcoal adsorber operation by verifying within 31 days after removal that a laboratory analysis of a representative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978.*

ASTM D3803-89 shall be used in place of ANSI N509-1976 as referenced in table 2 of Regulatory Guide 1.52. The laboratory test of charcoal should be conducted at a temperature of 30'C and a relative humidity of 95% within the tolerances specified by ASTM D3803-89.

MILLSTONE - UNIT 2 3/4 7-17 Amendment No. 2-, -2,

-47 , 4--9, 4-24, 449, 4--5, 8

Marci 10, 19999 PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

_/-the frequency specified in the Surveillance Frequency Control Program

e. At Mnee pcr 18 months by:

1. Verifying that the pressure drop across the combined HEPA filters and charcoal adsorber banks is less than 3.4 inches Water Gauge while operating the train at a flow rate of 2500 cfm +/- 10%.

/

2. Verifying that on a recirculation signal, with the Control Room Emergency /

Ventilation Train operating in the normal mode and the smoke purge mode, the train automatically switches into a recirculation mode of operation with flow through the HEPA filters and charcoal adsorber banks.

MILLSTONE - UNIT 2 3/4 7-17a Amendment No. 2-5, 72, 4-00, 4+-9, 4-2M, 4-49,4-7-5,2-28

April18,204-4 PLANT SYSTEMS

.3/4.7.11 ULTIMATE HEAT SINK LIMITING CONDITION FOR OPERATION 3.7.11 The ultimate heat sink shall be OPERABLE with a water temperature of less than or equal to 80'F.

APPLICABILITY: MODES 1, 2, 3, AND 4 ACTION:

With the UHS water temperature greater than 80'F, be in HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SURVEILLANCE REQUIREMENTS 4.7.11 The ultimate heat sink shall be determined OPERABLE:

a. At least once per 24 hour-, by verifying the water temperature to be within limits.

b. At least once per 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months by erifying the water temperature to be within limits when the water tempera re exceeds 75°F. +-

Ithe frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 7-34 Amendment No. 44-4, 4-6-2, 491, 2-1-3, 247-, 25-7,38.b

MarIh 16, 2006 ELECTRICAL POWER SYSTEMS ACTION (Continued)

Inoperable Equipment Required ACTION

e. Two diesel e. 1 Perform Surveillance Requirement 4.8.1.1.1 for the generators offsite circuits within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and at least once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months thereafter.

AND e.2 Restore one of the inoperable diesel generators to OPERABLE status within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or be in HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

AND e.3 Following restoration of one diesel generator restore remaining inoperable diesel generator to OPERABLE status following the time requirements of ACTION Statement b above based on the initial loss of the remaining inoperable diesel generator.

SURVEILLANCE REQUIREMENTS 4.8.1.1.1 Verify correct breaker alignment and indicated power available for each required offsite circuit at least nc per. 21*hur.s.

Ithe frequency specified in the Surveillance Frequency Control Proqram I MILLSTONE - UNIT 2 3/4 8-2a Amendment No. 4-3+, 2-3+, 274,291

july 25, 29 3 --

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) the frequency specified in the Surveillance Frequency Control Program 4.8.1.1.2 Each r/quired diesel generator shall be demonstrated OPERABLE:*

a. At ee per 3 .,ay*by:by:

1. Verifying the fuel level in the fuel oil supply tank, 2.

NOTES /

/

1. A modified diesel generator start involving idling and gradual acceleration to synchronous speed may be used as recommended by the manufacturer. When modified start procedures are not used, the requirements of SR 4.8.1.1.2.d. I must be met.

2. Performance of SR 4.8.1.1.2.d satisfies this Surveillance Requirement.

Verifying the diesel generator starts from standby conditions and achieves /

steady state voltage > 3740 V and < 4580 V, and Frequency > 58.8 Hz and

< 61.2 Hz.

3.

NOTES I. Diesel generator loading may include gradual loading as /

recommended by the manufacturer.

2. Momentary transients outside the load range do not invalidate this test.

3. This test shall be conducted on only one diesel generator at a time.

4. This test shall be preceded by and immediately follow without shutdown a successful performance of SR 4.8.1.1.2.a.2, or SRs 4.8.1.1.2.d. 1 and 4.8.1.1.2.d.2.

5. Performance of SR 4.8.1.1.2.d satisfies this Surveillance Requirement. /

Verifying the diesel generator is synchronized and loaded, and operates for

> 60 minutes at a load > 2475 kW and < 2750 kW.

All diesel starts may be preceded by an engine prelube period.

MILLSTONE - UNIT 2 3/4 8-3 Amendment No. 4-7-, 23-1-,2

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

b. The diesel fuel oil supply shall be checked by:

/

1. Checking for and removing accumulated water from each fuel oil storage tank at 9 as

2. Verifying fue il properties of new and stored fuel oil are tested in Oil accordance with, d maintained within the limits of, the Diesel Fuel Testing Program in a rdance with the Diesel Fuel Oil Testing Program.

C. At latoe e 8mnh

1. Deleted

2. the frequency specified in the Surveillance Frequency Control Program NOTE This surveillance shall not normally be performed in MODE 1, 2, 3, or 4. However, portions of the surveillance may be /

performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Verifying that the automatic time delay sequencer is OPERABLE with the following settings:

Sequence Time After Closing of Diesel Generator Step Output Breaker (Seconds)

Minimum Maximum 1 (TI) 1.5 2.2 2 (T 2 ) T, + 5.5 8.4 3 (T 3 ) T2 + 5.5 14.6 4 (T 4 ) T3 + 5.5 20.8 MILLSTONE - UNIT 2 3/4 8-3a Amendment No. 4-34, 23-, 2-59, 247

-Jttly 25,203-ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENT (Continued)

.,,jthe frequency specified in the Surveillance Frequency Control Program I

d. At ast-oncc pcr 184-days by:

1. Verifying the diesel starts from standby conditions and accelerates to

Ž_90% of rated speed and to Ž_97% of rated voltage within 15 seconds after the start signal.

2. Verifying the generator achieves steady state voltage >_3740 V and

4580 V, and frequency Ž_58.8 Hz and *61.2 Hz.

3.

/

NOTES /

1. Diesel generator loading may include gradual loading as recommended by the manufacturer.

2. Momentary transients outside the load range do not invalidate this test.

3. This test shall be conducted on only one diesel generator at a time.

4. This test shall be preceded by and immediately /1 follow without shutdown a successful performance of SRs 4.8.1.1.2.d. 1 and 4.8.1.1.2.d.2, or SR 4.8.1.1.2.a.2.

Verifying the diesel generator is synchronized and loaded, and operates for 2!60 minutes at a load _>2475 kW and < 2750 kW.

MILLSTONE - UNIT 2 3/4 8-4 Amendment No. 23-1,-2 4ttne 16, 998 ELECTRICAL POWER SYSTEMS 3/4 8.2 ONSITE POWER DISTRIBUTION SYSTEMS A.C. DISTRIBUTION - OPERATING LIMITING CONDITION FOR OPERATION 3.8.2.1 The following A.C. electrical busses shall be OPERABLE and energized from sources of power other than the diesel generators with tie breakers open between redundant busses:

4160 volt Emergency Bus # 24 C 4160 volt Emergency Bus #24 D 480 volt Emergency Load Center #22 E 480 volt Emergency Load Center #22 F 120 volt A.C. Vital Bus # VA-10 'F 120 volt A.C. Vital Bus # VA-20 120 volt A.C. Vital Bus # VA-30 ,1-120 volt A.C. Vital Bus # VA-40 1' APPLICABILITY: MODES 1, 2, 3 and 4.

ACTION:

With less than the above complement of A.C. busses OPERABLE, restore the inoperable bus and/

or associated load center to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or be in COLD SHUTDOWN within the next 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

SURVEILLANCE REQUIREMENTS 4.8.2.1 The specified A.C. busses shall be determined OPERABLE and energized from normal A.C. sources with tie breakers open between redundant busses at least

.. .. per 7 day by verifying correct breaker alignment and indicated po a Ithe frequency specified in the Surveillance Frequency Control Program I MILLSTONE - UNIT 2 3/4 8-6 Amendment No. 246

4tune 16,-1988 ELECTRICAL POWER SYSTEMS 3/4.8.2 ONSITE POWER DISTRIBUTION SYSTEMS A.C. DISTRIBUTION - OPERATING LIMITING CONDITION FOR OPERATION (Continued) 3.8.2. IA Inverters 5 and 6 shall be OPERABLE and available for automatic transfer via static switches VS 1 and VS2 to power busses VA- 10 and VA-20, respectively. ,[

APPLICABILITY: MODES 1, 2 & 3 ACTION:

a. With inverter 5 or 6 inoperable, restore the inverter to OPERABLE status within 7 days or be in HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

b. With inverter 5 or 6 unavailable for automatic transfer via static switch VS 1 or VS2 to power bus VA- 10 or VA-20, respectively, restore the ,t' automatic transfer capability within 7 days or be in HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

c. With inverters 5 and 6 inoperable or unavailable for automatic transfer via static switches VS1 and VS2 to power busses VA-10 and VA-20, ,F respectively, restore the inverters to OPERABLE status or restore their automatic transfer capability within 7 days or be in HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

SURVEILLANCE REQUIREMENTS 4.8.2. 1A a. Verify correct inverter voltage, frequency, and alignment for automatic transfer via static switches VS 1 and VS2 to power busses VA-10 and VA-20, respectively, at least once per 7 days.

b. Verify that busses VA-i and VA-20 automatically transfer to their alternate power sources, nverters 5 and 6, respectively, least enee p,-ere., iig during shut own.

Ithe frequency specified in the Surveillance Frequency Control Program I MILLSTONE - UNIT 2 3/4 8-6a Amendment No. 4-88, 2-1-6

Septem 1 ber 18, 2008 ELECTRICAL POWER SYSTEMS A.C. DISTRIBUTION - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.8.2.2 As a minimum, the following A.C. electrical busses shall be OPERABLE and energized from sources of power other than a diesel generator but aligned to an OPERABLE diesel generator:

1 - 4160 volt Emergency Bus I - 480 volt Emergency Load Center 2 - 120 volt A.C. Vital Busses APPLICABILITY: MODES 5 and 6.

ACTION:

With less than the above complement of A.C. busses OPERABLE and energized, suspend all operations involving CORE ALTERATIONS and positive reactivity additions that could result in loss of required SDM or boron concentration, and movement of recently irradiated fuel 1" assemblies.

SURVEILLANCE REQUIREMENTS 4.8.2.2 The specified A.C. busses shall be determined OPERABLE and energized from normal A.C. sources at'--- ---- r. daysby verifying correct breaker alignment and indicated power availability.

[the frequency specified in the Surveillance Frequency Control Program]

MILLSTONE - UNIT 2 3/4 8-7 Amendment No. +-9-7, 2-9, 305

july 29 , 200 ELECTRICAL POWER SYSTEMS D.C. DISTRIBUTION - OPERATING LIMITING CONDITION FOR OPERATION 3.8.2.3 125-volt D.C. bus Train A and 125-volt D.C. bus Train B electrical power subsystems [,

shall be OPERABLE.

APPLICABILITY: MODES 1, 2, 3 and 4.

ACTION:

With one 125-volt D.C. bus train inoperable, restore the inoperable 125-volt D.C. bus train to OPERABLE status within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or be in COLD SHUTDOWN within the next 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

SURVEILLANCE REQUIREMENTS 4.8.2.3.1 Each 125-volt D.C. bus train shall be determined OPERABLE at Per 7 days by verifying correct breaker alignment and indicated power availability.

4.8.2.3.2 Each 125-volt D.C. battery bank and charger of Train A a Train B shall be demonstrated OPERABLE:

a. By verifying at least enee per 7 days that that the attery cell parameters meet Table 4.8-1 Cate o limits.

b. By verifying at 4 psr-,,e, ye the b tery cell parameters meet Table 4.8-1 Category B limits. -

Ithe frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 8-8 Amendment No. 4-N8,0, 291

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

c. At.l-.. n er- 18 menths by verifying that:

1. The cells, cell plates and battery racks show no visual indication of physical damage or deterioration that could degrade battery performance, -

2. The cell-to-cell and terminal connections are clean, tight, free of corrosion nd coated with anti-corrosion material, and

3. e battery charger will supply at least 400 amperes at a minimum of 130 v its for at least 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

d. At -- -4.ef18-met, during shutdown, by verifying that the battery ca city is dequate to supply and maintain in OPERABLE status all of the actual emer ency 1 ads for 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months when the battery is subjected to a battery service test.

e. At !ea

er ,th,, during shutdown, by verifying that the battery cap i t 1 ast 80% of the manufacturer's rating when subjected to a perform c di harge test. This performance discharge test may be performed in lieu of the service test.

[the frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 8-9 Amendment No. 08, 80,-2-7 9

September 18, 2008 ELECTRICAL POWER SYSTEMS D.C. DISTRIBUTION - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.8.2.4 One 125 - volt D.C. bus train electrical power subsystem shall be OPERABLE:

APPLICABILITY: MODES 5 and 6.

ACTION:

With no 125-volt D.C. bus trains OPERABLE, suspend all operations involving CORE ALTERATIONS and positive reactivity additions that could result in loss of required SDM or boron concentration, and movement of recently irradiated fuel assemblies. -F-SURVEILLANCE REQUIREMENTS 4.8.2.4.1 The above required 125-volt D.C. bus train shall be determined OPERABLE at keast e,@ per-7 days by verifying correct breaker alignment and indicated power availabili 4.8.2.4.2 The above required 125-volt D.C. bus train battery bank and char shall be demonstrated OPERABLE per Surveillance Requirement 4.8.2.3.2.

Ithe frequency specified in the Surveillance Frequency Control Program I MILLSTONE - UNIT 2 3/4 8-10 Amendment No. 4-80, 4-9-7,2-79, 29-3, 40O 4uly29, 2003-ELECTRICAL POWER SYSTEMS D.C. DISTRIBUTION SYSTEMS (TURBINE BATTERY) - OPERATING LIMITING CONDITION FOR OPERATION 3.8.2.5 The Turbine Battery 125-volt D.C. electrical power subsystem shall be OPERABLE. /

APPLICABILITY: MODES 1, 2 & 3 ACTION:

a. With the Turbine Battery 125-volt D.C. electrical power subsystem inoperable, restore the subsystem to OPERABLE status within 7 days or be in HOT SHUTDO within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ,

[the frequency specified in the Surveillance Frequency Control Program ]

SURVEILLANCE REQUIREMENTS 4.8.2.5.1 Verify 125-volt D.C. bus 201D is OPE t 4.8.2.5.2 125-volt D.C. battery bank 2 sha e de strated OPERABLE:

a. By verifying at the battery cell parameters meet Table 4.8-2 Category A li

b. By verifying the battery cell parameters meet Table 4.8-2 Category limits.

c. Atee y verifying that:

1. The cells, c p1 es, and battery racks show no visual indication of physical ama e or deterioration that could degrade battery performance, ,.

and

2. T e cell o-cell and terminal connections are clean, tight, free of corrosion, nd c ted with anti-corrosion material.

d. At 1t during shutdown, by verifying that the battery capacity s adequate to supply and maintain in OPERABLE status all of the actual loads or 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months when the battery is subjected to a battery service test.

e. At* 6during shutdown, by verifying that the battery capacity is at least 80% of the manufacturer's rating when subjected to a performance discharge test. This performance discharge test may be performed in lieu of the battery service test.

MILLSTONE - UNIT 2 3/4 8-11 Amendment No. 4-88, 2-7-9

tifl.e 2..8, .2006 3/4.9 REFUELING OPERATIONS 3/4.9.1 BORON CONCENTRATIONS LIMITING CONDITION FOR OPERATION 3.9.1 The boron concentration of all filled portions of the Reactor Coolant System and the refueling canal shall be maintained sufficient to ensure that the more restrictive of following reactivity conditions is met:

a. Either a Keff of 0.95 or less, or

b. A boron concentration of greater than or equal to 1720 ppm.

APPLICABILITY: MODE 6.

NOTE Only applicable to the refueling canal when connected to the Reactor Coolant System ACTION:

With the requirements of the above specification not satisfied, within 15 minutes suspend all operations involving CORE ALTERATIONS and positive reactivity additions and initiate and 4 continue boration at greater than or equal to 40 gpm of boric acid solution at or greater than the required refueling water storage tank concentration (ppm) until Keff is reduced to less than or equal to 0.95 or the boron concentration is restored to greater than or equal to 1720 ppm, whichever is the more restrictive.

SURVEILLANCE REQUIREMENTS 4.9.1.1 The more restrictive of the above two reactivity conditions shall be determined prior to:

a. Removing or unbolting the reactor vessel head, and

b. Withdrawal of any CEA in excess of 3 feet from its fully inserted position within the reactor pressure vessel.

4.9.1.2 The boron concentration of all filled portions of the reactor coolant system and the refueling canal shall be determined by chemical analysis at e Pef

. 72 h..fs.

4.9.1.3 Deleted the frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 9-1 Amendment No. 20-1, 26-3, 280, 9 Juit 28, 2006 REFUELING OPERATIONS INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.9.2 Two source range neutron flux monitors shall be OPERABLE, each with continuous visual indication in the control room and one with audible indication in the containment, and control room.

APPLICABILITY: MODE 6.

ACTION:

a. With one of the above required monitors inoperable, immediately suspend all operations involving CORE ALTERATIONS and operations that would cause introduction of coolant into the RCS with boron concentration less than required to meet the boron concentration of LCO 3.9.1.

b. With both of the above required monitors inoperable, immediately initiate action to restore one monitor to OPERABLE status. Additionally, determine that the boron concentration of the Reactor Coolant System satisfies the requirements of LCO 3.9.1 within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months and at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter.

SURVEILLANCE REQUIREMENTS.

4.9.2 Each source range neutron flux monitor shall be demonstrated OPERABLE by performance of:

a. Deleted

b. A CHANNEL CALIBRATION at .... per- I*

12 menths*

c. A CHANNEL CHECK and verifica:tin aast -efieper12 heufs Ithe frequency specified in the Surveillance Frequency Control Program

Neutron detectors are excluded from CHANNEL CALIBRATION.

MILLSTONE - UNIT 2 3/4 9-2 Amendment No. 26-3, Sepwtfenm*e 2004 REFUELING OPERATIONS CONTAINMENT PENETRATIONS SURVEILLANCE REQUIREMENTS 4.9.4.1 Verify each required containment penetration is in the required status at least one Per 4.9.4.2 Deleted -F the frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 9-5 Amendment No. 240, 2 lne-28, 2006-REFUELING OPERATIONS SHUTDOWN COOLING AND COOLANT CIRCULATION - HIGH WATER LEVEL LIMITING CONDITION FOR OPERATION ACTION:

With no shutdown cooling train OPERABLE or in operation, perform the following actions:

a. Immediately suspend operations that would cause introduction of coolant into the RCS with boron concentration less than required to meet the boron concentration of LCO 3.9.1 and the loading of irradiated fuel assemblies in the core; and

b. Immediately initate action to restore one shutdown cooling train to OPERABLE status and operation; and

c. Within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months place the containment penetrations in the following status:

1. Close the equipment door and secure with at least four bolts; and

2. Close at least one personnel airlock door; and

3. Each penetration providing direct access from the containment atmosphere to the outside atmosphere shall be closed with a manual or automatic isolation valve, blind flange, or equivalent.

SURVEILLANCE REQUIREMENTS 4.9.8.1 One shutdown cooling train shall be verified to be in operation and circulating reactor coolant at a flow rate greater than or equal to 1000 gpm at least cncc per 12.,ho,,rs.

[the frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 9-8a Amendment No. 74, +-85, 249, 284,

-293

REFUELING OPERATIONS SHUTDOWN COOLING AND COOLANT CIRCULATION - LOW WATER LEVEL LIMITING CONDITION FOR OPERATION (continued)

c. Each penetration providing direct access from the containment atmosphere to the outside atmosphere shall be closed with a manual or automatic isolation valve, blind flange, or equivalent.

SURVEILLANCE REQUIREMENTS the frequency specified in the Surveillance Frequency Control Program 4.9.8.2.1 One shutdown cooling train shall be verified to bJ in operation and circulating reactor coolant at a flow rate greater than or equal to 1000 gpm at east oncc ef 12 haurf.

4.9.8.2.2 The required shutdown cooling pump, if not in operation, shall be determined OPERABLE . per-.-days

.ee- verifying correct breaker alignment and indicated power available.

lat the frequencv specified in the Surveillance Frequencv Control Propram MILLSTONE - UNIT 2 3/4 9-8c Amendment No. 49 1

REFUELING OPERATIONS WATER LEVEL - REACTOR VESSEL LIMITING CONDITION FOR OPERATION 3.9.11 As a minimum, 23.0 feet of water shall be maintained over the top of the reactor vessel flange.

/

APPLICABILITY: During CORE ALTERATIONS, except during latching and unlatching of control rod drive shafts.

During movement of irradiated fuel assemblies within containment.

ACTION:

With the water level less than that specified above, immediately suspend CORE ALTERATIONS and immediately suspend movement of irradiated fuel assemblies within containment.

SURVEILLANCE REQUIREMENTS 4.9.11 The water level shall be determined to be within its minimum depth at least *e,.-pc 24 hourfs t1 Ithe frequency specified in the Surveillance Frequency Control Program I MILLSTONE - UNIT 2 3/4 9-11 Amendment No.-263- J/

REFUELING OPERATIONS STORAGE POOL WATER LEVEL LIMITING CONDITION FOR OPERATION 3.9.12 As a minimum, 23 feet of water shall be maintained over the top of irradiated fuel assemblies seated in the storage racks.

APPLICABILITY: WHENEVER IRRADIATED FUEL ASSEMBLIES ARE IN THE STORAGE POOL.

ACTION:

With the requirement of the specification not satisfied, suspend all movement of fuel and spent fuel pool platform crane operations with loads in the fuel storage areas.

SURVEILLANCE REQUIREMENTS 4.9.12 The water level in the storage pool shall be determined to be within its minimum depth at -a ,rdys when irradiated fuel assemblies are in the fuel storage pool.

,-,t,-

the frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 9-12

November- 14, 2013 REFUELING OPERATIONS SHIELDED CASK LIMITING CONDITION FOR OPERATION 3.9.16 All fuel within a distance L from the center of the spent fuel pool cask laydown area shall have decayed for at least 90 days. The distance L equals the major dimension of the shielded cask.

t APPLICABILITY: Whenever a shielded cask is on the refueling floor.

ACTION:

With the requirements of the above specification not satisfied, do not move a shielded cask to the refueling floor. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.9.16 The decay time of all fuel within a distance L from the center of the spent fuel pool cask laydown area shall be determined to be > 90 days within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months prior to moving a shielded cask to the refueling floor and at 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months thereafter.

1-

[the frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 9-19 Amendment No. 30, 4-09, 4-72, 24-5, 4-6

REFUELING OPERATIONS SPENT FUEL POOL BORON CONCENTRATION I/

LIMITING CONDITION FOR OPERATION 3.9.17 The boron concentration in the spent fuel pool shall be greater than or equal to 1720 parts per million (ppm).

APPLICABILITY: Whenever any fuel assembly or consolidated fuel storage box, is stored in //

the spent fuel pool. /

ACTION:

With the boron concentration less than 1720 ppm, suspend the movement of all fuel, consolidated fuel storage boxes, and shielded casks, and immediately initiate action to restore the spent fuel pool boron concentration to within its limit.

The provisions of specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS I

/

4.9.17 Verify that the boron concentration is greater than or equal to 1720 ppm_.vey, 7 days, and within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months prior to the initial movement of a fuel assembly or conso itda d fuel storage box in the Spent Fuel Pool, or shielded cask over the cask laydown a at the frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 2 3/4 9-21 Amendment No. 4-09, 4--7, 4-5-8, 2-4-,

--2 November-28, 2000 SPECIAL TEST EXCEPTIONS GROUP HEIGHT AND INSERTION LIMITS LIMITING CONDITION FOR OPERATION 3.10.2 The requirements of Specifications 3.1.1.4, 3.1.3.1, 3.1.3.5, 3.1.3.6, 3.2.3 and 3.2.4 may be suspended during the performance of PHYSICS TESTS provided:

a. The THERMAL POWER is restricted to the test power plateau which shall not exceed 85% of RATED THERMAL POWER, and

b. The limits of Specification 3.2.1 are maintained and determined as specified in Specification 4.10.2 below.

APPLICABILITY: MODES 1 and 2.

ACTION:

With any of the limits of Specification 3.2.1 being exceeded while the requirements of Specifications 3.1.1.4, 3.1.3.1, 3.1.3.5, 3.1.3.6, 3.2.3 and 3.2.4 are suspended, immediately:

a. Reduce THERMAL POWER sufficiently to satisfy the requirements of Specification 3.2.1 or

b. Be in HOT STANDBY within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

SURVEILLANCE REQUIREMENTS 4.10.2.1 The THERMAL POWER shall be determined at l ..... during PHYSICS TESTS in which the requirements of Specifications 3.1.1.4 .1.3.. 1, 3.1.3.5, 3.1.3.6, 3.2.3 or 3.2.4 are suspended and shall be verified to be within the test p wer plateau.

4.10.2.2 The linear heat rate shall be determined to within the limits of Specification 3.2.1 by monitoring it continuously with the Incore Detect Monitoring System pursuant to the requirements of Specifications 4.2.1.3 during PHYS CS TESTS above 5% of RATED ,

THERMAL POWER in which the requirements of pecifications 3.1.1.4, 3.1.3.1, 3.1.3.5, 3.1.3.6, 3.2.3 or 3.2.4 are suspended.

Ithe frequency specified in the Surveillance Frequency Control Program I MILLSTONE - UNIT 2 3/4 10-2 Amendment No. 3-8, 5-2, 4-39, 2-50

Rine-2, .t201-2 ADMINISTRATIVE CONTROLS 6.27 CONTROL ROOM ENVELOPE HABITABILITY PROGRAM (Continued)

e. The quantitative limits on unfiltered air inleakage into the CRE. These limits shall be stated in a manner to allow direct comparison to the unfiltered air inleakage measured by the testing described in paragraph c. The unfiltered air inleakage limit for radiological challenges is the inleakage flow rate assumed in the licensing basis analyses of DBA consequences. Unfiltered air inleakage limits for hazardous chemicals must ensure that exposure of CRE occupants to these hazards will be within the assumptions in the licensing basis.

f. The provisions of Surveillance Requirement 4.0.2 are applicable to the frequencies for assessing CRE habitability and determining CRE unfiltered inleakage as required by paragraph c.

6.28 SNUBBER EXAMINATION, TESTING, AND SERVICE LIFE MONITORING PROGRAM This program conforms to the examination, testing, and service life monitoring for dynamic restraints (snubbers) in accordance with 10 CFR 50.55a inservice inspection (ISI) requirements for supports. The program shall be in accordance with the following:

a. This program shall meet 10 CFR 50.55a(g) ISI requirements for supports.

b. The program shall meet the requirements for ISI of supports set forth in subsequent editions of the Code of Record and addenda of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (BPV) Code and the ASME Code for Operation and Maintenance of Nuclear Power Plants (OM Code) that are incorporated by reference in 10 CFR 50.55a(b), subject to its limitations and modifications, and subject to Commission approval.

c. The program shall, as allowed by 10 CFR 50.55a(b)(3)(v), meet Subsection ISTA, "General Requirements" and Subsection ISTD, "Preservice and Inservice Examination and Testing of Dynamic Restraints (Snubbers) in Light-Water Reactor Nuclear Power Plants" in lieu of Section XI of the ASME BPV Code ISI requirements for snubbers, or meet authorized alternatives pursuant to 10 CFR 50.55a(a)(3).

d. The 120-month program updates shall be made in accordance with 10 CFR 50.55a (including 10 CFR 50.55a(b)(3)(v)) subject to the limitations and modifications listed therein.

SINSERT 1I MILLSTONE - UNIT 2 6-33 Amendment No. 305., 34- 1--

INSERT 1 6.29 SURVEILLANCE FREQUENCY CONTROL PROGRAM This program provides controls for surveillance frequencies. The program shall ensure that surveillance requirements specified in the technical specification are performed at intervals sufficient to assure the associated Limiting Conditions for Operation are met.

a. The Surveillance Frequency Control Program shall contain a list of frequencies of those surveillance requirements for which the frequency is controlled by the program.

b. Changes to the frequencies listed in the Surveillance Frequency Control Program shall be made in accordance with NEI 04-10, "Risk-Informed Method for Control of Surveillance Frequencies," Revision 1.

c. The provisions of Surveillance Requirements 4.0.2 and 4.0.3 are applicable to the frequencies established in the Surveillance Frequency Control Program.

Serial No.14-434 Docket No. 50-336 ATTACHMENT 4 Cross-References NUREG-1432 to MPS2 TS Surveillance Frequencies Removed DOMINION NUCLEAR CONNECTICUT, INC.

MILLSTONE POWER STATION UNIT 2

Serial No.14-434 Docket No. 50-336 Attachment 4, Page 1 of 12 TS Section Title/ Surveillance Description* TSTF425 T . . MPS2 Shutdown Margin Verify SDM in Modes 3, 4, and 5 SR 3.1.1.1 SR 4.1.1.1 Reactivity Balance Verify Core Reactivity ++/-1% SR 3.1.2.1 SR 4.1.1.2 CEA Alignment Verify Rod Position Within Alignment SR 3.1.4.1 SR 4.1.3.1.1 Verify Rod Motion Inhibit SR 3.1.4.2 SR 4.1.3.1.4.b Verify CEA Deviation Circuit SR 3.1.4.3 SR 4.1.3.1.3 Verify CEA Freedom of Movement SR 3.1.4.4 SR 4.1.3.1.2 Perform Channel Functional Test of Reed Switch SR 3.1.4.5 ---

Perform CEA drop time with Tavg> 515°F and all SR 4.1.3.4.c RCPs operatingprior to reactorcriticality Position Indication Channels Verify Pulse Counter Within 6 Steps of Reed Switch --- SR 4.1.3.3 Counters Shutdown CEA Insertion Limits Verify CEAs Withdrawn SR 3.1.5.1 SR 4.1.3.5 Regulating CEA Insertion Limits Verify Regulating CEAs Within Limits SR 3.1.6.1 SR 4.1.3.6.1 Verify Accumulated Time With Regulated CEA Below Limit SR 3.1.6.2 SR 4.1.3.6.2 Verify PDIL Alarm Circuit SR 3.1.6.3 SR 4.1.3.6.3 Control Rod Drive Mechanisms Verify Mechanisms are De-Energized --- SR 4 1.3.7 Special Test Exceptions - SDM Verify Each CEA Not Inserted is Within the Acceptance Criteria for Negative Reactivity Addition SR 3.1.7.1 Special Test Exceptions - Modes 1 and 2 Verify Thermal Power < Test Power Plateau SR 3.1.8.1 SR 4.10.2.1 Linear Heat Rate Verify ASI Alarm Setpoints Within Limits of COLR SR 3.2.1.1 SR 4.2.1.2.b Verify Incore Local Power Density Alarms SR 3.2.1.2 SR 4.2.1.3.a Verify Local Incore Power Density Setpoints are SR 3.2.1.3 SR 4.2.1.3.b Within Limits of COLR Verify CEAs are Withdrawn > Long Term Steady State SR 4.2.1.2.a Insertion Limits Fy Limits Verify the Value of FxT SR 3.2.2.1 Fr Limits Verify the Value of F r SR 3.2.3.1 SR 4.2.3.2.b Tq Limits Verify Tq is Within Limits SR 3.2.4.1 SR 4.2.4.1 Note 1 - This system is not included in the MPS2 design or TS.

--- Surveillance not included in STS or MPS2 TSs

Italicized text denotes MPS2-specific surveillances

Serial No.14-434 Docket No. 50-336 Attachment 4, Page 2 of 12 TS Section Title/ Surveillance Description* TSTF 425 MPS2 DNB Margin Verify Cold Leg Temperature, PressurizerPressure, SR 4.2.6.1 and RCS Flow Rate Axial Shape Index (ASI)

Verify ASI is Within Limits SR 3.2.5.1 SR 4.2.6.1 RPS Instrumentation - Operating Table 4.3-1 Perform Channel Check SR 3.3.1.1 Functional Units (FU)s 2 through 9, and 11 Perform Calibration (Heat Balance Only) SR 3.3.1.2 Table 4.3-1 FU 2.a SR 3.3.1.3 Table 4.3-1 Calibrate Power Range Excore Channels Using Incore FU 2.a Perform Channel Functional Test of Each Channel SR 3.3.1.4 Table 4.3-1 FUs 2 through 9 Perform Channel Calibration of Excore Channels SR 3.3.1.5 ---

Perform Channel Calibration of Each Channel 4.3.1.1.2 and Table 4.3-1 Including Auto Bypass Removal Function FUs 2 through 11 Verify Response Time SR 3.3.1.9 SR 4.3.1.1.3 RPS Instrumentation - Shutdown Perform Channel Check - Wide Range Power SR 3.3.2.1 Table 4.3-1 Channel FUll Perform Channel Functional Test - Power Rate of SR 3.3.2.2 Change Perform Channel Functional Test - Auto Bypass SR 3.3.2.3 ---

Removal Function Perform Channel Calibration, Including Bypass SR 3.3.2.4 ---

Removal Function RPS Logic and Trip Initiation Perform Channel Functional Test of Each RTCB SR 3.3.3.1 Table 4.3-1 Channel Channel FU 15 Perform Channel Functional Test of Each Logic SR 3.3.3.2 Table 4.3-1 Channel Channel FUs 13 and 14 Perform Channel Functional Test, Including Table 4.3-1 Verification of UV and Shunt Trips of Each RTCB SR 3.3.3.4 Channel EU 15 Channel ESFAS Instrumentation Table 4.3-2 Perform a Channel Check SR 3.3.4.1 Channel Check Column - FUs 1.b &

c, 2.b, 3.c & d, 4.b & c, 5 c & d, 6.b, 9.b, and 10.a Table 4.3-2 Perform Channel Functional Test SR 3.3.4.2 Channel Functional Test Column-FUs 1.b&c, 2.b, 3.c & d, 4.b & c, 5.c

& d, 6.b, 9.b, and 10.a Note 1 - This system is not included in the MPS2 design or TS.

--- Surveillance not included in STS or MPS2 TSs

Italicized text denotes MPS2-specific surveillances

Serial No.14-434 Docket No. 50-336 Attachment 4, Page 3 of 12 TS Section Title/ Surveillance Description* TSTF 425 MPS2 Table 4.3-2 Perform Channel Calibration of Each Channel, Channel Calibration Column includin BypassnRemoal Functionsf ESR 3.3.4.4 FUs 1.b & c, 2.b, 3.c & d, 4.b & c, 5.c including Bypass Removal Functions & d, 6.b,, 9.b, and 10.a SR 4.3.2.1.2 Verify Response Time SR 3.3.4.5 SR 4.3.2.1.3 ESFAS Logic and Manual Trip Table 4.3-2 Perform Channel Functional Test - Logic Channels SR 3.3.5.1 Channel Functional Test Column -

FUs l.d, 2.c, 3.e, 4.d, 5.e, 6.c, & 9.c Table 4.3-2 Perform Channel Functional Test on Each Manual SR 3.3.5.2 Channel Functional Test Column -

Trip Function FUs I.a,, 2.a, 3.a & b, 4.a, 5.a & b, 6.a, and 9.a DG LOVS Table 4.3-2 Perform Channel Check SR 3.3.6.1 Channel Check Column -

FUs 8.a & b Table 4.3-2 Perform Channel Functional Test SR 3.3.6.2 Channel Functional Test Column -

FUs 8.a & b Table 4.3-2 Perform Channel Calibration SR 3.3.6.3 Channel Calibration Column -

FUs 8.a & b ESFAS Sensor Cabinet Power Supply Drawers Verify the Power Supply are Energized by Visual --- SR 4.3.2.2.1 Inspection of Indication Lamps Verify the Sensor Cabinet Power Supply --- SR 4.3.2.2.2 Auctioneering Circuit Containment Purge Isolation Signal (CPIS)

Perform Channel Check SR 3.3.7.1 ---

Perform Channel Functional Test Each Rad Monitor SR 3.3.7.2 Perform Channel Functional Test CPIS Actuation SR 3.3.7.3 Logic Channel Perform Channel Calibration SR 3.3.7.4 ---

Perform Channel Functional Test SR 3.3.7.5 ---

Verify CPIS Response Time - Rad Monitor Channels SR 3.3.7.6 ---

Control Room Isolation System (CRIS)

Perform Channel Check on Control Room Radiation Table 4.3-3 Monitor Channel Check Column - FU 1.b Perform Channel Functional Test - Radiation Monitor Table 4.3-3 Channels SR 3.3.8.2 Channel Functional Test Column -

FU 1.b Perform Channel Functional Test - Actuation Logic SR 3.3.8.3 ---

Rad Monitor Channels SR 3Table 4.3-3 Perform Channel Calibration -

3.3.8.4 Channel Calibration Column - FU 1.b Perform Channel Functional Test - Manual Trip SR 3.3.8.5 ---

Channel Note 1 - This system is not included in the MPS2 design or TS.

--- Surveillance not included in STS or MPS2 TSs

Italicized text denotes MPS2-specific surveillances

Serial No.14-434 Docket No. 50-336 Attachment 4, Page 4 of 12 TS Section Title/ Surveillance Description* TSTF 425 MPS2 Verify Response Time SR 3.3.8.6 SR 4.3.3.1.3 CVSC Isolation Signal Perform Channel Check SR 3.3.9.1 Notel Perform Channel Functional Test - CVCS Isolation Channel SR 3.3.9.2 Notel Perform Channel Calibration - CVCS Isolation SR 3.3.9.3 Notel Pressure Indicating Channel Shield Building Filtration Actuation Signal Table 4.3-2 Perform Channel Functional Test - Auto Actuation Channel SR 3.3.10.1 Channel Functional Test Column FUs 5.c & d & e Perform Channel Functional Test - SBFAS Manual Table 4.3-2 Trip Channel SR 3.3.10.2 Channel Functional Test Column FUs 5.a &b PAM Instrumentation Perform Channel Check - Normalized Energized Inst. SR 3.3.11.1 SR 4.3.3.8 Perform Channel Calibration SR 3.3.11.2 SR 4.3.3.8 Remote Shutdown System Perform Channel Check SR 3.3.12.1 SR 4.3.3.5 Verify Each Control Circuit and Transfer Switch Can SR 3.3.12.2 Perform its Intended function Perform Channel Calibration Each Instrument SR 3.3.12.3 SR 4.3.3.5 Channel Perform Channel Functional Test Rx Trip Circuit SR 3.3.12.4 Breaker Open/Close Indication Power Monitor Channels Perform Channel Check SR 3.3.13.1 ---

Perform Channel Functional Test SR 3.3.13.2 ---

Perform Channel Calibration SR 3.3.13.3 ---

RCS Pressure, Temperature, and Flow (DNB) Limits Verify Pressurizer Pressure SR 3.4.1.1 ---

Verify RCS Cold Leg Temperature SR 3.4.1.2 ---

Verify RCS Total Flow Rate SR 3.4.1.3 ---

Verify by Precision Heat Balance - RCS Total Flow SR 3.4.1.4 ---

RCS Minimum Temperature for Criticality Verify RCS Tav.g in Each Loop SR 3.4.2.1 SR 4.1.1.5 RCS P/T Limits Verify RCS Pressure, Temperature, and H/U and C/D Rates SR 3.4.3.1 SR 4.4.9.1a RCS Loops Modes I and 2 Verify Each Loop in Operation SR 3.4.4.1 SR 4.4.1.1 RCS Loops Mode 3 Verify One Loop in Operation SR 3.4.5.1 SR 4.4.1.2.2 Verify Secondary Side Water Level in Each S/G SR 3.4.5.2 SR 4.4.1.2.3 Note 1 - This system is not included in the MPS2 design or TS.

--- Surveillance not included in STS or MPS2 TSs

Italicized text denotes MPS2-specific surveillances

Serial No.14-434 Docket No. 50-336 Attachment 4, Page 5 of 12 TS Section Title/ Surveillance Description*:' TSTF 425 MPS2 Verify Correct Breaker Alignment and Indicated Power SR 3.4.5.3 SR 4.4.1.2.1 Available to Each Required Pump RCS Loops Mode 4 Verify One Loop in Operation SR 3.4.6.1 SR 4.4.1.3.3 Verify Secondary Side Water Level in Each S/G SR 3.4.6.2 SR 4.4.1.3.2 Verify Correct Breaker Alignment and Indicated Power SR 3.4.6.3 SR 4.4.1.3.1 Available to Each Required Pump RCS Loops Mode 5, Loops Filled Verify Required SDC Train in Operation SR 3.4.7.1 SR 4.4.1.4.3 Verify Secondary Side Water Level in Each S/G SR 3.4.7.2 SR 4.4.1.4.2 Verify Correct Breaker alignment and Indicated Power SR 3.4.7.3 SR 4.4.1.4.1 Available to Each Required SDC Pump RCS Loops Mode 5, Loops Not Filled Verify Required SDC Train in Operation SR 3.4.8.1 SR 4.4.1.5.2 Verify Correct Breaker Alignment and Indicated Power SR 3.4.8.2 SR 4.4.1.5.1 Available to Each Required SDC Pump Reactor Coolant Pumps Verify Two RCPs Motor Circuit Breaker are --- SR 4.4.1.6 Disconnected from Their Power Supply Pressurizer Verify Water Level SR 3.4.9.1 SR 4.4.4.1 Verify Capacity of Required Pressurizer Heaters SR 3.4.9.2 SR 4.4.4.2 Verify Required Pressurizer Heaters Capable of Being SR 3.4.9.3 ---

Powered from Emergency Bus.

Pressurizer PORV Perform a Complete Cycle of Each Block valve SR 3.4.11.1 SR 4.4.3.2 Perform a Complete Cycle of Each PORV SR 3.4.11.2 SR 4.4.3.1.c Perform a Complete Cycle of Each Solenoid Air Control Valve and Check Valve on the Accumulators Verify PORVs and Block Valves are Capable of Being SR 3.4.11.4 ---

Powered from Emergency Power Perform a Channel Functional Test --- SR 4.4.3.1 .a Perform a Channel Calibration --- SR 4.4.3.1.b LTOP System Verify a Maximum of One HPSI Pump is Capable of SR 3.4.12.1 SR 4.4.9.3.3 Injecting into the RCS Verify a Maximum of One Charging Pump is Capable SR 3.4.12.2 SR 4.4.9.3.2 of Injecting into the RCS Verify Each SIT is Isolated SR 3.4.12.3 ---

Verify Required RCS Vent >[1.3] Square Inches Open SR 3.4.12.4 SR 4.4.9.3.4 Verify PORV Block Valve is Open for Each Required SR 3.4.12.5 SR 4.4.9.3.1.c PORV Perform Channel Functional Test on PORV SR 3.4.12.6 SR 4.4.9.3.1.a Note 1 - This system is not included in the MPS2 design or TS.

--- Surveillance not included in STS or MPS2 TSs

Italicized text denotes MPS2-specific surveillances

Serial No.14-434 Docket No. 50-336 Attachment 4, Page 6 of 12 TS Section Title/ Surveillance Description* TSTF 425 MPS2 Perform Channel Calibration on Each Required PORV SR 3.4.12.7 SR 4.4.9.3.1.b Actuation Channel RCS Operational Leakage Verify RCS Operational Leakage SR 3.4.13.1 SR 4.4.6.2.1 Verify <150 GPD Through Any One SG Leakage SR 3.4.13.2 SR 4.4.6.2.2 RCS PIV Leakage Verify Leakage from Each is < 0.5 gpm SR 3.4.14.1 Verify SDC Autoclosure Interlock Prevents Opening SR 3.4.14.2 ---

Verify SDC Autoclosure Interlock Auto Close SR 3.4.14.3 ---

RCS Leakage Detection Instrumentation Perform Channel Check Containment Atmosphere SR 3.4.15.1 SR 4.3.3.1.1/SR 4.4.6.1.a Radiation Monitor Perform Channel Functional Test Containment SR 3.4.15.2 SR 4.3.3.1.1/ SR 4.4.6.1.a Atmosphere Rad Monitor Perform Channel Calibration Containment Sump Monitor SR 3.4.15.3 SR 4.4.6.1.b Perform Channel Calibration Containment SR 3.4.15.4 SR 4.3.3.1.1/ SR 4.4.6.1.a Atmosphere Radioactivity Monitor Perform Channel Calibration Containment Air Cooler SR 3.4.15.5 ---

RCS Specific Activity Verify RCS Gross Specific Activity SR 3.4.16.1 ---

Verify RCS Dose Equivalent 1-131 SR 3.4.16.2 SR 4.4.8.2 Determine E Bar SR 3.4.16.3 ---

Verify Xe-133 < 11 OOpCi/gm --- SR 4.4.8.1 RCS Loops Test Exceptions Verify Thermal Power < 5% SR 3.4.17.1 ---

Safety Injection Tanks Verify SIT Isolation Valve Open SR 3.5.1.1 SR 4.5.1.a Verify Borated Water Volume SR 3.5.1.2 SR 4.5.1.b Verify N2 Pressure SR 3.5.1.3 SR 4.5.1.c Verify Boron Concentration SR 3.5.1.4 SR 4.5.1.d Verify Power Removed from Isolation Valve SR 3.5.1.5 SR 4.5.1.e ECCS - Operating Verify Valve are in Position and Power Removed SR 3.5.2.1 SR 4.5.2.b Verify Valve Position SR 3.5.2.2 SR 4.5.2.a Verify Piping Full of Water SR 3.5.2.3 ---

Verify Automatic Valve Actuation SR 3.5.2.6 SR 4.5.2.f Verify ECCS Pump Starts Automatically SR 3.5.2.7 SR 4.5.2. g Verify LPSI Pump Stops on Actuation Signal SR 3.5.2.8 SR 4.5.2. h Verify Throttle Valve Position SR 3.5.2.9 SR 4.5.2.i.2 Verify by Inspection, Each ECCS Train Sump Suction SR 3.5.2.10 SR 4.5.2.j is Not Restricted Note 1 - This system is not included in the MPS2 design or TS.

--- Surveillance not included in STS or MPS2 TSs

Italicized text denotes MPS2-specific surveillances

Serial No.14-434 Docket No. 50-336 Attachment 4, Page 7 of 12 TS Section Title/ Surveillance Description* TSTF 425 MPS2 Verify SDC Open Permissive Interlocks Prevent SDC Inlet Isolation Valves From Being Opened on RCS --- SR 4.5.2.k pressures > 300 RWT Verify Water Temperature SR 3.5.4.1 SR 4.5.4.b & c Verify Water Volume SR 3.5.4.2 SR 4.5.4.a.1 Verify Boron Concentration SR 3.5.4.3 SR 4.5.4.a.2 Trisodium Phosphate Verify TSP Baskets Contain > 291 ft 3 SR 3.5.5.1 SR 4.5.5.1 Verify Sample of TSP Baskets Provide Adequate pH SR 3.5.5.2 SR 4.5.5.2 Containment Air Locks Verify Only One Door Can be Opened at a Time SR 3.6.2.2 SR 4.6.1.3.2 Verify the Equipment Hatch is Closed and Sealed --- SR 4.6.1.1 .b Containment Isolation Valves Verify 42" Purge Valves Sealed Closed SR 3.6.3.1 SR 4.6.3.2 Verify 8" Purge Valves Closed SR 3.6.3.2 ---

Verify Valves Outside Containment in Correct Position SR 3.6.3.3 SR 4.6.1.1.a Verify Isolation Time of Automatic Power Operated SR 3.6.3.5 ---

Valves Perform Leak Rate Test of Purge Valves SR 3.6.3.6 ---

Verify Automatic Valves Actuate to Correct Position SR 3.6.3.7 SR 4.6.3.1.b Verify Purge Valves Blocked Closed SR 3.6.3.8 ---

Containment Pressure Verify Pressure SR 3.6.4.1 SR 4.6.1.4 Containment Air Temperature Verify Average Air Temperature SR 3.6.5.1 SR 4.6.1.5 Containment Spray and Cooling Systems SR Verify Valve Position 3.6.6A.1 SR 4.6.2.1.1.a SR Operate Each Cooling Train Fan 3.6.6AS2 SR 4.6.2.1.2.a Verify Each Cooling Train Cooling Water Flow Rate > SR

[2000] GPM to Each Fan 3.6.6A.3 SR 3.6.6A.4 ---

Verify Spray Piping Full of Water SR Verify Automatic Valves Actuate on Signal 3.6.6A.6 SR 4.6.2.1.1 .c SR Verify Pump Start on Actuation Signal 3.6.6A.7 SR 4.6.2.1.1.d SR Verify Cooling Train Start on Actuation Signal 3.6.6A.8 SR 4.6.2.1.2.c Verify Spray Nozzle is Unobstructed SR SR 4.6.2.1.1.e Note 1 - This system is not included in the MPS2 design or TS.

--- Surveillance not included in STS or MPS2 TSs

Italicized text denotes MPS2-specific surveillances

Serial No.14-434 Docket No. 50-336 Attachment 4, Page 8 of 12 TS Section Title/ Surveillance Description* TSTF 425 MPS2 3.6.6A.9 Spray Additive System Verify Valve Position SR 3.6.7.1 Note 1 Verify Tank Solution Volume SR 3.6.7.2 Note 1 Verify Tank Solution Concentration SR 3.6.7.3 Note 1 Verify Actuation -. Each Flow Path Valve SR 3.6.7.5 Note 1 Verify Spray Additive Flow Rate SR 3.6.7.6 Note 1 Shield Building Exhaust Air Cleanup System (SBEACS)

Operate Each Train with Heaters on for> 15 minutes SR 3.6.8.1 SR 4.6.5.1 Verify Actuation on Signal SR 3.6.8.3 SR 4.6.5.1.d.2 Verify Filter Bypass can be Opened SR 3.6.8.4 ---

Verify System Flow Rate SR 3.6.8.5 SR 4.6.5.1.b.3 Verify PressureDrop Across Filter Banks --- SR 4.6.5.1 .d. 1 Hydrogen Mixing System (HMS)

Operate Each Train for >15 minutes SR 3.6.9.1 SR 4.6.4.4.b Verify Each Train's Flow Rate on Slow Speed SR 3.6.9.2 ---

Verify Each Train Starts Automatically SR 3.6.9.3 ---

Verify Each Train Starts Manually from the Control Room --- SR 4.6.4.4.a Iodine Cleanup System Operate Each Train with Heaters on for > 15 minutes SR 3.6.10.1 Note 1 Verify Train Actuation SR 3.6.10.3 Note 1 Verify Filter Bypass Operation SR 3.6.10.4 Note 1 Shield Building Verify Annulus Negative Pressure SR 3.6.11.1 ---

Verify One Access Door in Each Access is Closed SR 3.6.11.2 SR 4.6.5.2.1 Verify Building can be Maintained at a Negative Pressure > -0.25 inch Water Gauge with One Train SR 3.6.11.4 SR 4.6.5.2.2 Main Steam Isolation Valves Verify Valves Actuate on Signal SR 3.7.2.2 Table 4.3-2, FU 4d MFIVs and MFRVs Verify Valves Actuate SR 3.7.3.2 SR 4.7.1.6.a & b Verify FeedwaterPump Trip on MS Isolation Signal --- SR 4.7.1.6.c & d Atmospheric Dump Valves -

Verify Dump Valves Cycle SR 3.7.4.1 SR 4.7.1.7 Verify Block Valves Cycle SR 3.7.4.2 ---

Steam GeneratorBlowdown Isolation Valves Verify Valve Closure Time --- SR 4.7.1.8 AFW Verify Valve Position SR 3.7.5.1 SR 4.7.1.2.a Verify Automatic Valve Actuation SR 3.7.5.3 SR 4.7.1.2.c Note 1 - This system is not included in the MPS2 design or TS.

--- Surveillance not included in STS or MPS2 TSs

Italicized text denotes MPS2-specific surveillances

Serial No.14-434 Docket No. 50-336 Attachment 4, Page 9 of 12 TS Section Title/ Surveillance Description* TSTF 425 MPS2 Verify Automatic Pump Actuation SR 3.7.5.4 SR 4.7.1.2.d Condensate Storage Tank Verify Level of CST SR 3.7.6.1 SR 4.7.1.3 Component Cooling Verify Valve Position SR 3.7.7.1 SR 4.7.3.1.a Verify Automatic Valve Actuation SR 3.7.7.2 SR 4.7.3.1 .b Verify Automatic Pump Actuation SR 3.7.7.3 SR 4.7.3.1.c Service Water Verify Valve Position SR 3.7.8.1 SR 4.7.4.1.a Verify Automatic Valve Actuation SR 3.7.8.2 SR 4.7.4.1.b Verify Automatic Pump Actuation SR 3.7.8.3 SR 4.7.4.1.c Ultimate Heat Sink Verify Water Level SR 3.7.9.1 ---

Verify Water Temperature SR 3.7.9.2 SR 4.7.11 .a Operate Each Cooling Tower SR 3.7.9.3 ---

Essential Chilled Water Verify Valve Position SR 3.7.10.1 Note 1 Verify Automatic Actuation of Components SR 3.7.10.2 Note 1 CR Emergency Air Cleanup System Operate Train with Heaters on for_> 15 minutes SR 3.7.11.1 SR 4.7.6.1.b Verify Train Actuation Actual or Simulated Signal SR 3.7.11.3 ---

Verify Manual Train Actuation --- SR 4.7.6.1.b Verify Envelope Pressurization SR 3.7.11.4 --

Verify PressureDrop Across FilterAssembly --- SR 4.7.6.1 .e. 1 Verify Actuation to Recirculation Mode --- SR 4.7.6.1.e.2 CREATCS Verify Train Capacity SR 3.7.12.1 ----

Verify Control Room Temperature is Within Limit --- SR 4.7.6.1 .a ECCS PREACS Operate Heaters SR 3.7.13.1 Note 1 Verify Train Actuation Actual or Simulated Signal SR 3.13.3 Note 1 Verify Envelope Negative Pressure SR 3.13.4 Note 1 Verify Bypass Damper can be Opened SR 3.13.5 Note 1 Fuel Building Air Cleanup Operate Heaters SR 3.7.14.1 Note 1 Verify Automatic Train Actuation SR 3.7.14.3 Note 1 Verify Envelope Negative Pressure SR 3.7.14.4 Note 1 Verify Bypass Damper Can be Opened SR 3.7.14.5 Note 1 Penetration Room Air Cleanup System -

Note 1 - This system is not included in the MPS2 design or TS.

--- Surveillance not included in STS or MPS2 TSs

Italicized text denotes MPS2-specific surveillances

Serial No.14-434 Docket No. 50-336 Attachment 4, Page 10 of 12 TS Section Title/ Surveillance Description* TSTF 425 MPS2 Operate Heaters SR 3.7.15.1 Note 1 Verify Automatic Train Actuation SR 3.7.15.3 Note 1 Verify Envelope Pressurization SR 3.7.15.4 Note 1 Verify Bypass Damper Closure SR 3.7.15.5 Note 1 Fuel Storage Pool Water Level Verify Water Level SR 3.7.16.1 SR 4.9.12 Fuel Storage Pool Boron Verify Boron Concentration SR 3.7.17.1 SR 4.9.17 Secondary Specific Activity Verify Secondary Activity SR 3.7.19.1 SR 4.7.1.4 AC Sources -Operating Verify Breaker Alignment Offsite Circuits SR 3.8.1.1 SR 4.8.1.1.1 Verify EDG Starts - Achieves Voltage & Frequency SR 3.8.1.2 SR 4.8.1.1.2.a.2 Synchronize and Load for > 60 Minutes Every 31 days SR 3.8.1.3 SR 4.8.1.1.2.a.3 Verify Day Tank Level SR 3.8.1.4 SR 4.8.1.1.2.a.1 Remove Accumulate Water from Day Tank SR 3.8.1.5 SR 4.8.1.1.2.b. 1 Verify Operation of Transfer Pump SR 3.8.1.6 ---

Verify EDG Starts - Achieves Voltage & Frequency in SR 3.8.1.7 SR 4.8.1.1.2.d.1, 2 & 3 10 Seconds -184 days SR_.81._S_48..12..1_2& _

Verify Manual Transfer of AC power Sources - Offsite SR 3.8.1.8 Sources Verify Largest Load Rejection SR 3.8.1.9 SR 4.8.1.1.2.c.3 Verify EDG Does Not Trip with Load Rejection SR 3.8.1.10 SR 4.8.1.1.2.c.4 Verify De-energize, Load Shed and Re-energize SR 3.8.1.11 SR 4.8.1.1.2.c.7 Emergency Bus with Loss of Offsite Power Verify EDG Start on ESF Signal SR 3.8.1.12 SR 4.8.1.1.2.c.8 Verify EDG Noncritical Trips are Bypassed SR 3.8.1.13 SR 4.8.1.1.2.c.6 Run EDG for 24 Hours SR 3.8.1.14 ---

Verify EDG Starts Post Operation - Achieves Voltage SR 3.8.1.15 SR 4.8.1.1.2.c.9

& Frequency Verify EDG Synchronizes w/ Offsite Power and SR 3.8.1.16 Transfers Load Verify Test Mode is Overrode on ESF Signal SR 3.8.1.17 ---

Verify Load Sequencers are within Design Tolerance SR 3.8.1.18 SR 4.8.1.1.2.c.2 Verify EDG Start on Loss of Offsite Power with ESF SR 3.8.1.19 SR 4.8.1.1.2.c.5 Verify When Started Simultaneously Each EDGs SR 3.8.1.20 Reach Rated Voltage and Frequency Diesel FO and Starting Air Verify FO Storage Tank Volume SR 3.8.3.1 SR 4.8.1.1.2.a.1 Verify Lube Oil Inventory SR 3.8.3.2 ---

Note 1 - This system is not included in the MPS2 design or TS.

--- Surveillance not included in STS or MPS2 TSs

Italicized text denotes MPS2-specific surveillances

Serial No.14-434 Docket No. 50-336 Attachment 4, Page 11 of 12 TS Section Title/ Surveillance Description* TSTF 425 MPS2 Verify EDG Start Air Receive Pressure SR 3.8.3.4 ---

Check and Remove Accumulate Water from FO Tank SR 3.8.3.5 SR 4.8.1.1.2.b.1 DC Sources Operating Verify Battery Terminal Voltage SR 3.8.4.1 ---

Verify Station Battery Chargers Capable of Supplying SR 3.8.4.2 SR 4.8.2.3.2.c.3

[x]Amp for [y]Hours Perform Battery Service Test SR 3.8.4.3 SR 4.8.2.3.2.d Battery Parameters Verify Each Battery Float Current is < [2] amps. SR 3.8.6.1 ---

Verify Each Battery Pilot Cell Voltage is >[2.07] V SR 3.8.6.2 SR 4.8.2.3.2.a Verify Each Battery Cell Electrolyte Level is > to SR 3.8.6.3 SR 4.8.2.3.2.a Minimum Design Limits Verify Each Battery Pilot Cell Temperature > to SR 3.8.6.4 Minimum Design Limits Verify Each Battery Connected Cell Voltage is>[2.07] V. SR 3.8.6.5 SR 4.8.2.3.2.b Verify Station and EDG Battery Capacity - >80% After SR 3.8.6.6 SR 4.8.2.3.2.e Performance Test Physical Inspection of Cell Platesand Battery Racks --- SR 4.8.2.3.2.c. 1 Physical Inspection of Terminal Connections --- SR 4.8.2.3.2.c.2 Verify the Battery ChargerSupply> 400 amps for 12 hrs --- SR 4.8.2.3.2.c.3 Inverters - Operating Verify Correct Inverter Voltage & Alignment to SR 3.8.7.1 SR 4.8.2.1A.a Required AC Vital Buses Verify Busses Auto Transfer to Alternate Power Supply --- SR 4.8.2.1 A.b Inverters - Shutdown Verify Correct Inverter Voltage & Alignment to SR 3.8.8.1 Required AC Vital Buses Distribution System - Operating Verify Correct Breaker Alignments and Voltage to AC, DC, and AC Vital Bus Electrical Power Distribution SR 3.8.9.1 SR 4.8.2.1/SR 4.8.2.3.1 Subsystems Distribution System - Shutdown Verify Correct Breaker Alignments and Voltage to AC, DC, and AC Vital Bus Electrical Power Distribution SR 3.8.10.1 SR 4.8.2.2/SR 4.8.2.4.1 Subsystems DC DistributionSystem (Turbine Battery) - Operating Verify the 125-volt DC Bus is Operable --- SR 4.8.2.5.1 Verify 125-V DC Battery Bank Meet CatA Cell --- SR 4.8.2.5.2.a Parameterse Verify 125-V DC Battery Bank Meet Cat B Cell --- SR 4.8.2.5.2.b Parameters Verify Cells, Cell Plates, Racks, Terminal Connections --- SR 4.8.2.5.2.c are not Damaged and Free of Corrosion Perform a Battery Service Test --- SR 4.8.2.5.2.d Perform a PerformanceDischarge Test --- SR 4.8.2.5.2.e Note 1 - This system is not included in the MPS2 design or TS.

--- Surveillance not included in STS or MPS2 TSs

Italicized text denotes MPS2-specific surveillances

Serial No.14-434 Docket No. 50-336 Attachment 4, Page 12 of 12 TS Section Title/ Surveillance Description* TSTF 425 MPS2 Boron Concentration Verify Boron Concentration is Within the Limit SR 3.9.1.1 SR 4.9.1.2 Specified in COLR Nuclear Instrumentation Perform Channel Check SR 3.9.2.1 SR 4.9.2.c Perform Channel Calibration SR 3.9.2.2 SR 4.9.2.b Containment Penetrations Verify Each Required Containment Penetration is in SR 3.9.3.1 SR 4.9.4.1 the Required Status Verify Each Required Containment Purge and Exhaust Valve Actuates to the Isolation Position on an SR 3.9.3.2 Actuated or Simulated Actuation Signal SDC and Coolant Circulation - High Water Level Verify One Loop is in Operation and Circulating SR 3.9.4.1 SR 4.9.8.1 Reactor Coolant at a Flow Rate of > [2200] gpm SDC and Coolant Circulation - Low Water Level Verify One Loop is in Operation and Circulating SR 3.9.5.1 SR 4.9.8.2.1 Reactor Coolant at a flow rate of > [2800] gpm Verify Correct Breaker Alignment and Indicated Power Available to the Required SDC Pump that is Not in SR 3.9.5.2 SR 4.9.8.2.2 Operation Refueling Cavity Water Level Verify Refueling Cavity Water Level is >23 ft Above SR 3.9.6.1 SR 4.9.11 the Top of Reactor Vessel Flange Shielded Cask Verify the Decay Time of Fuel in the Vicinity of the SR 4.9.16 Cask Lay Down Area Note 1 - This system is not included in the MPS2 design or TS.

--- Surveillance not included in STS or MPS2 TSs

Italicized text denotes MPS2-specific surveillances

Serial No.14-434 Docket No. 50-336 ATTACHMENT 5 Significant Hazards Consideration Determination DOMINION NUCLEAR CONNECTICUT, INC.

MILLSTONE POWER STATION UNIT 2

Serial No.14-434 Docket No. 50-336 Attachment 5, Page 1 of 2 PROPOSED NO SIGNIFICANT HAZARDS CONSIDERATION This amendment request involves the adoption of approved changes to the standard technical specifications (STS) for Combustion Engineering Pressurized Water Reactors (NUREG-1432), to allow relocation of specific technical specification (TS) surveillance frequencies to a licensee-controlled program. The proposed changes are described in Technical Specification Task Force (TSTF) Traveler, TSTF-425, Revision 3 (ADAMS Accession No. ML090850642), "Relocate Surveillance Frequencies to Licensee Control

- RITSTF Initiative 5b" and are described in the Notice of Availability published in the Federal Register on July 6, 2009 (74 FR 31996).

The proposed changes are consistent with NRC-approved Industry/TSTF Traveler, TSTF-425, Revision 3, "Relocate Surveillance Frequencies to Licensee Control-RITSTF Initiative 5b." The proposed changes relocate surveillance frequencies to a licensee-controlled program, the Surveillance Frequency Control Program (SFCP). The changes are applicable to licensees using probabilistic risk guidelines contained in NRC-approved NEI 04-10, "Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies," (ADAMS Accession No.

071360456). In addition, administrative/editorial deviations of the TSTF-425 inserts and the existing TS wording are being proposed to fit the Millstone Power Station Unit 2 TS format.

Basis for proposed no significant hazards consideration: As required by 10 CFR 50.91 (a), DNC's analysis of the issue of no significant hazards consideration is presented below:

1. Do the proposed changes involve a significant increase in the probability or consequences of any accident previously evaluated?

Response: No.

The proposed changes relocate the specified frequencies for periodic surveillance requirements to licensee control under a new Surveillance Frequency Control Program.

Surveillance frequencies are not an initiator to any accident previously evaluated. As a result, the probability of any accident previously evaluated is not significantly increased.

The systems and components required by the TSs for which the surveillance frequencies are relocated are still required to be operable, meet the acceptance criteria for the surveillance requirements, and be capable of performing any mitigation function assumed in the accident analysis. As a result, the consequences of any accident previously evaluated are not significantly increased.

Therefore, the proposed changes do not involve a significant increase in the probability or consequences of an accident previously evaluated.

Serial No.14-434 Docket No. 50-336 Attachment 5, Page 2 of 2

2. Do the proposed changes create the possibility of a new or different kind of accident from any previously evaluated?

Response: No.

No new or different accidents result from utilizing the proposed changes. The changes do not involve a physical alteration of the plant (i.e., no new or different type of equipment will be installed) or a change in the methods governing normal plant operation. In addition, the changes do not impose any new or different requirements.

The changes do not alter assumptions made in the safety analysis. The proposed changes are consistent with the safety analysis assumptions and current plant operating practice.

Therefore, the proposed changes do not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Do the proposed changes involve a significant reduction in the margin of safety?

Response: No.

The design, operation, testing methods, and acceptance criteria for systems, structures, and components, specified in applicable codes and standards (or alternatives approved for use by the NRC) will continue to be met as described in the plant licensing basis (including the final safety analysis report and bases to TS), since these are not affected by changes to the surveillance frequencies. Similarly, there is no impact to safety analysis acceptance criteria as described in the plant licensing basis. To evaluate a change in the relocated surveillance frequency, DNC will perform a probabilistic risk evaluation using the guidance contained in NRC approved NEI 04-10, Rev. 1, in accordance with the Surveillance Frequency Control Program. NEI 04-10, Rev. 1, methodology provides reasonable acceptance guidelines and methods for evaluating the risk increase of proposed changes to surveillance frequencies consistent with Regulatory Guide 1.177.

Therefore, the proposed changes do not involve a significant reduction in a margin of safety.

Based upon the reasoning presented above, DNC concludes that the requested changes do not involve a significant hazards consideration as set forth in 10 CFR 50.92(c), Issuance of Amendment.

Serial No.14-434 Docket No. 50-336 ATTACHMENT 6 Marked-Up Technical Specifications Bases Changes (For Information Only)

DOMINION NUCLEAR CONNECTICUT, INC.

MILLSTONE POWER STATION UNIT 2

Insert 2a The surveillance frequency is controlled under the Surveillance Frequency Control Program.

Insert 2b These surveillance frequencies are controlled under the Surveillance Frequency Control Program.

L=BDCR 14 MP2 009 BASES 3/4.1.3 MOVEABLE CONTROL ASSEMBLIES (Continued)

The CEA motion inhibit permits CEA motion within the requirements of LCO 3.1.3.6, "Regulating Control Element Assembly (CEA) Insertion Limits," and the CEA deviation circuit prevents regulating CEAs from being misaligned from other CEAs in the group. With the CEA motion inhibit inoperable, a time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is allowed for restoring the CEA motion inhibit to OPERABLE status, or placing and maintaining the CEA drive switch in either the "off' or "manual" position, fully withdrawing all CEAs in group 7 to < 5% insertion. Placing the CEA drive switch in the "off' or "manual" position ensures the CEAs will not move in response to Reactor Regulating System automatic motion commands. Withdrawal of the CEAs to the positions required in the Required ACTION B.2 ensures that core perturbations in local burnup, peaking factors, and SHUTDOWN MARGIN will not be more adverse than the Conditions assumed in the safety analyses and LCO setpoint determination. Required ACTION B.2 is modified by a Note indicating that performing this Required ACTION is not required when in conflict with Required ACTIONS A.1 or C. 1.

Continued operation is not allowed in the case of more than one CEA misaligned from any other CEA in its group by > 20 steps, or one or more CEAs untrippable. This is because these cases are indicative of a loss of SHUTDOWN MARGIN and power distribution changes, and a loss of safety function, respectively.

OPERABILITY of the CEA position indicators (Specification 3.1.3.3) is required to determine CEA positions and thereby ensure compliance with the CEA alignment and insertion limits and ensures proper operation of the CEA Motion Inhibit and CEA deviation block circuit.

The CEA "Full In" and "Full Out" limit Position Indicator channels provide an additional independent means for determining the CEA positions when the CEAs are at either their fully inserted or fully withdrawn positions. Therefore, the ACTION statements applicable to inoperable CEA position indicators permit continued operations when the positions of CEAs with inoperable position indicators can be verified by the "Full In" or "Full Out" limit Position Indicator channels. lat the frequency specified in the Surveillance Frequency Control Program CEA positions and OPERABILITY of the*CEA n indicators are required to be verified en a ne..inal basis ef en. per- 12 h. . t more frequent verifications required if an automatic monitoring channel is inoperable. These '.r.ifi.ati.n frcgu....... r. adequate for asuastrig n that

..... the .... v.... ale.kl lGf' . .....

. . satisfied.-.

..... 'I--------* nsert 2a The maximum CEA drop time permitted by Specification 3.1.3.4 is the assumed CEA drop time used in the accident analyses. Measurement with Tavg > 515°F and with all reactor coolant pumps operating ensures that the measured drop times will be representative of insertion times experienced during a reactor trip at operating conditions.

MILLSTONE - UNIT 2 B 3/4 1-4a Amendment No. 4-3-3, 2-1-6, 2-80, Aek1.ew.dged by-NR1 ette" dated 6/28/05

Se..erIbU* 25, 2003 POWER DISTRIBUTION LIMITS BASES by the ACTION statements since these additional restrictions provide adequate provisions to assure that the assumptions used in establishing the Linear Heat Rate, Thermal Margin/Low Pressure and Local Power Density - High LCOs and LSSS setpoints remain valid. An AZIMUTHAL POWER TILT > 0.10 is not expected and if it should occur, subsequent operation would be restricted to only those operations required to identify the cause of this unexpected tilt.

Core power distribution is a concern any time the reactor is critical. The Total Integrated Radial Peaking Factor - FTr LCO, however, is only applicable in MODE 1 above 20% of RATED THERMAL POWER. The reasons that this LCO is not applicable below 20% of RATED THERMAL POWER are:

a. Data from the incore detectors are used for determining the measured radial peaking factors. Technical Specification 3.2.3 is not applicable below 20% of RATED THERMAL POWER because the accuracy of the neutron flux information from the incore detectors is not reliable at THERMAL POWER

< 20% RATED THERMAL POWER.

b. When core power is below 20% of RATED THERMAL POWER, the core is operating well below its thermal limits, and the Local Power Density (fuel pellet melting) and Thermal Margin/Low Pressure (DNB) trips are highly conservative.

The surveillance requirements for verifying that FTr and Tq are within their limits provide assurance that the actual values of FTr and Tq do not exceed the assumed values. Verifying FTr after each fuel loading prior to exceeding 70% of RATED THERMAL POWER rovides additional assurance that the core was properly loaded.

Insert 2b 3/4.2.6 DNB MARGIN The limitations provided in this specification ensure that the assumed margins to DNB are maintained. The limiting values of the parameters in this specification are those assumed as the initial conditions in the accident and transient analyses; therefore, operation must be maintained within the specified limits for the accident and transient analyses to remain valid.

MILLSTONE - UNIT 2 B 3/4 2-2 Amendment No. 3-8, -52,4+-2, 4-39, 4-5-5, 2-30, 80-

LDDCR 04-NIP2-O 16 Fbrdiary 24, 2005 3/4.3 INSTRUMENTATION BASES 3/4.3.1 AND 3/4.3.2 PROTECTIVE AND ENGINEERED SAFETY FEATURES (ESF) INSTRUMENTATION The OPERABILITY of the protective and ESF instrumentation systems and bypasses ensure that 1) the associated ESF action and/or reactor trip will be initiated when the parameter monitored by each channel or combination thereof exceeds its setpoint, 2) the specified coincidence logic is maintained, 3) sufficient redundancy is maintained to permit a channel to be out of service for testing or maintenance, and 4) sufficient system functional capability is available for protective and ESF purposes from diverse parameters.

The OPERABILITY of these systems is required to provide the overall reliability, redundance and diversity assumed available in the facility design for the protection and mitigation of accident and transient conditions. The integrated operation of each of these systems is consistent with the assumptions used in the accident analyses.

ACTION Statement 2 of Tables 3.3-1 and 3.3-3 requires an inoperable Reactor Protection ,/

System (RPS) or Engineered Safety Feature Actuation System (ESFAS) channel to be placed in the bypassed or tripped condition within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The inoperable channel may remain in the bypassed condition for a maximum of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months . While in the bypassed condition, the affected functional unit trip coincidence will be 2 out of 3. After 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months , the channel must either be declared OPERABLE, or placed in the tripped condition. If the channel is placed in the tripped condition, the affected functional unit trip coincidence will become 1 out of 3. One additional channel may be removed from service for up to 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months , provided one of the inoperable channels is placed in the tripped condition.

Plant operation with an inoperable pressurizer high pressure reactor protection channel in the tripped condition is restricted because of the potential inadvertent opening of both pressurizer power operated relief valves (PORVs) if a second pressurizer high pressure reactor protection channel failed while the first channel was in the tripped condition. This plant operating restriction is contained in the Technical Requirements Manual.

The reactor trip switchgear consists of eight reactor trip circuit breakers, which are operated in four sets of two breakers (four channels). Each of the four trip legs consists of two reactor trip circuit breakers in series. The two reactor trip circuit breakers within a trip leg are actuated by separate initiation circuits. For example, if a breaker receives an open signal in trip leg A, an identical breaker in trip leg B will also receive an open signal. This arrangement ensures that power is interrupted to both Control Element Drive Mechanism buses, thus preventing a trip of only half of the control element assemblies (a half trip). Any one inoperable breaker in a channel will make the entire channel inoperable.

The surveillance requirements specified for these systems ensure that the overall system functional capability is maintained comparable to the original design standards. The-periodic sur~cillancc tests pcr-fermed at the m-inaimu-fm frequencies resu-fficient to defiemnstra;te, thir, pbiitr-- nsert 2b The surveillance testing verifies OPERABILITY of the RPS by overlap testing of the four interconnected modules: measurement channels, bistable trip units, RPS logic, and reactor trip circuit breakers. When testing the measurement channels or bistable trip units that provide an automatic reactor trip function, the associated RPS channel will be removed from service, MILLSTONE - UNIT 2 B 3/4 3-1 Amendment No. 46-7, 4-88, 498, 22-5, 2-2, Ae1.ko....ldged by NRC letterf dated-,60X/05

L=BDCR 06 N4P2 036 Octabr*J 12, 2006 3/4.3 INSTRUMENTATION BASES 3/4.3.1 AND 3/4.3.2 PROTECTIVE AND ENGINEERED SAFETY FEATURES (ESF) INSTRUMENTATION (continued)

ACTION Statement 8 applies to two inoperable automatic bypass removal channels. If the bypass removal channels cannot be restored to OPERABLE status, the associated RPS channel may be considered OPERABLE only if the bypass is not in effect. Otherwise, the affected RPS channels must be declared inoperable, and the bypass either removed or the bypass removal channel repaired. Also, ACTION Statement 8 provides for the restoration of the one affected automatic trip channel to OPERABLE status within the allowed outage time specified under ACTION Statement 2.

ACTION Statements 7 and 8 contain the term "disable the bypass channel." Compliance with ACTION Statements 7 or 8 is met by placing or verifying the Zero Mode Bypass Switch(es) in "Off." No further action (i.e., key removal, periodic verification, etc.) is required. These switches are administratively controlled via station procedures; therefore the requirements of ACTION Statements 7 and 8 are continuously met. periodically SR 4.3.1.1.2 and SR 4.3.2.1.2 specify a CHANNEL FUN TIONAL TEST of the bypass-Insert 2a function and automatic bypass removal once within 92 d s prior to each reactor startu The total bypass function shall be demonstrated OPERABLE at. least @nee on+during CHANNEL CALIBRATION testing of each channel affected by bypass operation. he CHANNEL FUNCTIONAL TEST is similar to the CHANNEL FUNCTIONAL TESTS already required by SR 4.3.1.1.1 and SR 4.3.2.1.1, except the CHANNEL FUNCTIONAL TEST is applicable only to bypass functions and is performed once within 92 days prior to each startup.

The MPS2 RPS is an analog system while the design of the MPS2 ESFAS includes both an analog portion and a digital portion. With respect to the analog portion of the systems, a successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other TS tests at least once per refueling interval with applicable extensions. Proper operation of bypass permissives is critical during plant startup because the bypasses must be in place to allow startup operation and must be removed at the appropriate points during power ascent to enable certain reactor trips. Consequently, the appropriate time to verify bypass removal function OPERABILITY is just prior to startup. The allowance to conduct this test within 92 days of startup is based on the reliability analysis presented in topical report CEN-327, "RPS/ESFAS Extended Test Interval Evaluation," which is referenced in NUREG-1432 and is applicable to MPS2. Once the operating bypasses are removed, the bypasses must not fail in such a way that the associated trip function gets inadvertently bypassed. This feature is verified by the trip function CHANNEL FUNCTIONAL TESTS SR 4.3.1.1.1 and SR 4.3.2.1.1. Therefore, further testing of the bypass function after startup is unnecessary.

MILLSTONE - UNIT 2 B 3/4 3-1b Amendment Ne.

LBD3ECR 06 N4P2 036 Octeber- 12, 2006 3/4.3 INSTRUMENTATION BASES 3/4.3.1 AND 3/4.3.2 PROTECTIVE AND ENGINEERED SAFETY FEATURES (ESF) INSTRUMENTATION (continued)

The ESFAS includes four sensor subsystems and two actuation subsystems for each of the functional units identified in Table 3.3-3. Each sensor subsystem includes measurement channels and bistable trip units. Each of the four sensor subsystem channels monitors redundant and independent process measurement channels. Each sensor is monitored by at least one bistable.

The bistable associated with each ESFAS Function will trip when the monitored variable exceeds the trip setpoint. When tripped, the sensor subsystems provide outputs to the two actuation subsystems.

The two independent actuation subsystems each compare the four associated sensor subsystem outputs. If a trip occurs in two or more sensor subsystem channels, the two-out-of-four automatic actuation logic will initiate one train of ESFAS. An Automatic Test Inserter (ATI), for which the automatic actuation logic OPERABILITY requirements of this specification do not apply, provides automatic test capability for both the sensor subsystems and the actuation subsystems.

The provisions of Specification 4.0.4 are not applicable for the CHANNEL FUNCTIONAL TEST of the Engineered Safety Feature Actuation System automatic actuation logic associated with Pressurizer Pressure Safety Injection, Pressurizer Pressure Containment Isolation, Steam Generator Pressure Main Steam Line Isolation, and Pressurizer Pressure Enclosure Building Filtration for entry into MODE 3 or other specified conditions. After entering MODE 3, pressurizer pressure and steam generator pressure will be increased and the blocks of the ESF actuations on low pressurizer pressure and low steam generator pressure will be automatically removed. After the blocks have been removed, the CHANNEL FUNCTIONAL TEST of the ESF automatic actuation logic can be performed. The CHANNEL FUNCTIONAL TEST of the ESF automatic actuation logic must be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishing the appropriate plant conditions, and prior to entry into MODE 2.

Lperiodic __

The measurement of response time at the speeified frcgicneies provides assurance that the protective and ESF action function associated with each channel is completed within the time limit assumed in the accident analyses. No credit was taken in the analyses for those channels with response times indicated as not a icable. The Reactor Protective and Engineered Safety Feature response times are contained in e Millstone Unit No. 2 Technical Requirements Manual.

Changes to the Technical Requirements anual require a 10CFR50.59 review as well as a review by the Site Operations Review Committe Insert 2b MILLSTONE - UNIT 2 B 3/4 3-1c Amendmen IV

LBDCG* 13 N92 016 Octeber 16, 2013 3/4.4 REACTOR COOLANT SYSTEM BASES various methods. These methods include, but are not limited to, placing the NORMAL/ISOLATE switch at the associated Bottle Up Panel in the "ISOLATE" position or pulling the control power fuses for the associated PORV control circuit.

Although the block valve may be designated inoperable, it may be able to be manually opened and closed and in this manner can be used to perform its function. Block valve inoperability may be due to seat leakage, instrumentation problems, or other causes that do not prevent manual use and do not create a possibility for a small break LOCA. This condition is only intended to permit operation of the plant for a limited period of time. The block valve should normally be available to allow PORV operation for automatic mitigation of overpressure events. The block valves must be returned to OPERABLE status prior to entering MODE 3 after a refueling outage.

If more than one PORV is inoperable and not capable of being manually cycled, it is necessary to either restore at least one valve within the completion time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or isolate the flow path by closing and removing the power to the associated block valve and cooldown the RCS to MODE 4.

SURVEILLANCE REQUIREMENT 4.4.3. I.C requires operating each PORV through one complete cycle of full travel at conditions representative of MODES 3 or 4. This is normally performed in MODE 3 or 4 as the unit is descending in power to commence a refueling outage.

This test will normally be a static test, whereby a PORV will be exposed to MODE 3 or 4 temperatures, the block valve closed, and the PORV tested to verify it strokes through one complete cycle of full travel. PORV cycling demonstrates its function. The Fr,.qu.n.y .f 18 menths is basedo a typi.al rcfuit.ling. y.l. and industy a...pt.d pra .... SURVEILLANCE REQUIREMENT 4.4.3. l.C is consistent with the NRC staff position outlined in Generic Letter 90-06, which requires that the 18 menth PORV stroke test be performed at conditions representative of MODE 3 or 4. Testing in the manner described is also consistent with the guidance in NUREG 1482, "Gui elines for Inservice Testing at Nuclear Power Plants," Section 4.2.10, that describes the PORVs nction during reactor startup and shutdown to protect the stemction reactor vessel and coolant system m low-temperature overpressurization conditions, and indicates they should be exercised b ore system conditions warrant vessel protection. If post maintenance retest is warranted, the a ected valve(s) will be stroked under ambient conditions while in Mode 5, 6, or defueled. A Hot unctional Test is required to be performed in MODE 4 prior to entry into MODE 3. The actual s oke time in the open and close direction will be 1 measured, recorded and compared to the t t results obtained during pre-installation testing to assess acceptability of the affected valve(s). Insert 2a SURVEILLANCE REQUIREMENT 4.4.3.2 verifies that a block valve(s) can be closed if necessary. This SURVEILLANCE REQUIREMENT is not required to be performed with the block valve(s) closed in accordance with the ACTIONS of TS 3.4.3. Opening the block valve(s) in this condition increases the risk of an unisolable leak from the RCS since the PORV(s) is MILLSTONE - UNIT 2 B 3/4 4-2a Amendment No. 2-2, 3-7, 2,66, 9-7,

+18-5,24--1-,2-6+-

O..-M-4*2--O..I REACTOR COOLANT SYSTEM BASES 3/4.4.6 REACTOR COOLANT SYSTEM LEAKAGE 3/4.4.6.2 REACTOR COOLANT SYSTEM OPERATIONAL LEAKAGE SURVEILLANCE REQUIREMENTS (Continued)

The Sur..eillance. Frequ..ey of.72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months ' a reasonable interval to trend primary to secondary LEAKAGE and recognizes the importance early leakage detection in the prevention of accidents. The primary to secondary LEAKAGEs determined using continuous process radiation monitors or radiochemical grab sampling i ccordance with the EPRI guidelines (Reference 5).

BACKGROUND [frequency specified in the Surveillance Frequency Control Program Components that contain or transport the coolant to or from the reactor core make up the reactor coolant system (RCS). Component joints are made by welding, bolting, rolling, or pressure loading, and valves isolate connecting systems from the RCS.

During plant life, the joint and valve interfaces can produce varying amounts of reactor coolant LEAKAGE, through either normal operational wear or mechanical deterioration. The purpose of the RCS Operational LEAKAGE LCO is to limit system operation in the presence of LEAKAGE from these sources to amounts that do not compromise safety. This LCO specifies the types and amounts of LEAKAGE.

10 CFR 50, Appendix A, GDC 30 (Reference 1), requires means for detecting and, to the extent practical, identifying the source of reactor coolant LEAKAGE. Regulatory Guide 1.45 (Reference 2) describes acceptable methods for selecting leakage detection systems.

The safety significance of RCS LEAKAGE varies widely depending on its source, rate, and duration. Therefore, detecting and monitoring reactor coolant LEAKAGE into the containment area is necessary. Quickly separating the IDENTIFIED LEAKAGE from the UNIDENTIFIED LEAKAGE is necessary to provide quantitative information to the operators, allowing them to take corrective action should a leak occur detrimental to the safety of the facility and the public.

A limited amount of leakage inside containment is expected from auxiliary systems that cannot be made 100% leaktight. Leakage from these systems should be detected, located, and isolated from the containment atmosphere, if possible, to not interfere with RCS LEAKAGE detection.

This LCO deals with protection of the reactor coolant pressure boundary (RCPB) from degradation and the core from inadequate cooling, in addition to preventing the accident analysis radiation release assumptions from being exceeded. The consequences of violating this LCO include the possibility of a loss of coolant accident (LOCA).

MILLSTONE - UNIT 2 B 3/4 4-3e Amendmen

IVIMaIlI 18, 26008 rBDCGR 09 MP2 013 REACTOR COOLANT SYSTEM BASES 3/4.4.8 SPECIFIC ACTIVITY (continued)

ACTIONS (continued) d.

With the RCS DOSE EQUIVALENT XE-133 greater than the LCO limit, DOSE EQUIVALENT XE-133 must be restored to within limit within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months . The allowed completion time of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months is acceptable since it is expected that, if there were a noble gas spike, the normal coolant noble gas concentration would be restored within this time period. Also, there is a low probability of a SLB or SGTR occurring during this time period.

A statement in ACTION d. indicates the provisions of LCO 3.0.4 are not applicable. This exception to LCO 3.0.4 permits entry into the applicable MODE(S), relying on ACTION d. while the DOSE EQUIVALENT XE-133 LCO is not met. This exception is acceptable due to the significant conservatism incorporated into the RCS specific activity limit, the low probability of an event which is limiting due to exceeding this limit, and the ability to restore transient-specific activity excursions while the plant remains at, or proceeds to, POWER OPERATION.

e.

If the required action and completion time of ACTION d. is not met, the reactor must be brought to HOT STANDBY (MODE 3) within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and COLD SHUTDOWN (MODE 5) within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed completion times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE REQUIREMENTS 4.4.8.1 Surveillance Requirement 4.4.8.1 requires performing a gamma isotopic analysis as a measure of the noble gas specific activity of the reactor coolant at least once eve-y 7 days. This measurement is the sum of the degassed gamma activities and the gaseous gamma activities in the sample taken.

This Surveillance Requirement provides an indication of any increase in the noble gas specific activity. Insert 2a Trending the results of this Surveillance Requirement allows proper remedial action to be taken before reaching the LCO limit under normal operating conditions. T1he s. rvcillat.. 7 day freqiucney eansiders the low probability of a gross fttel failuire dur-ing this time.

MILLSTONE - UNIT 2 B 3/4 4-4d

Marceh 18, 2008 LB1DCRO08 N4P2 013 REACTOR COOLANT SYSTEM BASES 3/4.4.8 SPECIFIC ACTIVITY (continued)

SURVEILLANCE REQUIREMENTS (continued) 4.4.8.1 (continued)

Due to the inherent difficulty in detecting Kr-85 in a reactor coolant sample due to masking from radioisotopes with similar decay energies, such as F-18 and 1-134, it is acceptable to include the minimum detectable activity for Kr-85 in the Surveillance Requirement 4.4.8.1 calculation. If a specific noble gas nuclide listed in the definition of DOSE EQUIVALENT XE-133 is not detected, it should be assumed to be present at the minimum detectable activity.

A Note modifies the Surveillance Requirement to allow entry into and operation in MODE 4, MODE 3, and MODE 2 prior to performing the Surveillance Requirement. This allows the Surveillance Requirement to be performed in those MODES, prior to entering MODE 1.

4.4.8.2 ]frequency specified in the Surveillance Frequency Control Program -

This Surveillance Requirement is performed o ensure iodine specific activity remains within the LCO limit during normal operation and frowing fast power changes when iodine spiking is more apt to occur. The 14 day fiequerfey is adequate to trend changes in the iodine activity leveL,

.. nsider.ing noble gas

. a ti.it is . .iteredevery 7,,y s. The frequency of between 2 and 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after a power change > 15% RTP within a 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months period is established because the iodine levels peak during this time following iodine spike initiation; samples at other times would provide inaccurate results.

The Note modifies this Surveillance Requirement to allow entry into and operation in MODE 4, MODE 3, and MODE 2 prior to performing the Surveillance Requirement. This allows the Surveillance Requirement to be performed in those MODES, prior to entering MODE 1.

REFERENCES

1. 10CFR50.67.

2. Standard Review Plan (SRP) Section 15.0.1 "Radiological Consequence Analyses Using Alternate Source Terms."

3. FSAR, Section 14.1.5.

4. FSAR, Section 14.6.3.

MILLSTONE - UNIT 2 B 3/4 4-4e

-june H, 2067 L C*.E, [-M2- 3/4.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

BASES 3/4.5.2 and 3/4.5.3 ECCS SUBSYSTEMS (continued)

Surveillance Requirement 4.5.2.a verifies the correct alignment for manual, power operated, and automatic valves in the ECCS flow paths to provide assurance that the proper flow paths will exist for ECCS operation. This surveillance does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve that receives an actuation signal is allowed to be in a nonaccident position provided the valve automatically repositions within the proper stroke time.

This surveillance does not require any testing or valve manipulation. Rather, it involves verification that those valves capable of being mispositioned are in the correct position. The 31 day frcgucnc i~ pr-piate beeause the valves are @peratcd under preeedural contral and an imprpcr alvcpostio Would only affcct a single train. This f-requcncty has been1 shown to be aeeeptablc thfeugh epertn excincc.

Surveillance Requirement 4.5.2.b verifies proper va osition to ensure that the flow path from the ECCS pumps to the RCS is maintained. Misalignment o-ese valves could render both ECCS trains inoperable. Securing these valves in position by remo -" power to the valve operator ensures that the valves cannot be inadvertently misaligned r ch osition as the result of an active failure. A3 a r sdre fal ~ ]: R admini11 strative eentrols enuing thta ipsitioned valve is ant unlikcly p-"iilt.

Surveillance Requirements 4.5.2.c and 4.5.2.d, which address periodic surveillance testing of the ECCS pumps (high pressure and low pressure safety injection pumps) to detect gross degradation caused by impeller structural damage or other hydraulic component problems, is required by the ASME Code for Operation and Maintenance of Nuclear Power Plants (ASME OM Code). This ,

type of testing may be accomplished by measuring the pump developed head at only one point of the pump characteristic curve. This verifies both that the measured performance is within an acceptable tolerance of the original pump baseline performance and that the performance at the test flow is greater than or equal to the performance assumed in the unit safety analysis. The surveillance requirements are specified in the Inservice Testing Program. The ASME OM Code ]/

provides the activities and frequencies necessary to satisfy the requirements.

Surveillance Requirement 4.5.2.e, which addresses periodic surveillance testing of the charging pumps to detect gross degradation caused by hydraulic component problems, is required by the ASME OM Code. For positive displacement pumps, this type of testing may be accomplished by comparing the measured pump flow, discharge pressure and vibration to their respective acceptance criteria. Acceptance criteria are verified to bound the assumptions utilized in accident analyses. This verifies both that the measured performance is within an acceptable tolerance of the original pump baseline performance and that the performance at the test point is greater than or equal to the performance assumed for mitigation of the beyond design basis events. The surveillance requirements are specified in the Inservice Testing Program. The ASME OM Code provides the activities and frequencies necessary to satisfy the requirements.

MILLSTONE - UNIT 2 B 3/4 5-2b Amendment No. 4-5, 64-, 72, 1-59, 4S5, 24-5, 24-6, 24-7, 272, 2,2-, 2-36, 28-

Septc*meir 1 9, 2004 3/4.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

BASES 3/4.5.2 and 3/4.5.3 ECCS SUBSYSTEMS (continued)

Surveillance Requirements 4.5.2.f, 4.5.2.g, and 4.5.2.h demonstrate that each automatic ECCS flow path valve actuates to the required position on an actual or simulated actuation signal (SIAS or SRAS), that each ECCS pump starts on receipt of an actual or simulated actuation signal (SIAS), and that the LPSI pumps stop on receipt of an actual or simulated actuation signal (SRAS). This surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls. The 18 m.nth frequen. y is based a,- thn need to perform these sur.veillan.es under-the eenditions that apply during a plant outtage, and the pctential for-unplanned tfansients if the surveillanees were performed with the reaeter atpower.

The1t 8 month Li eIIuL.y is alu aL*eptablk based on esideLati, of the desig 1 11 Ir.iability (anld con.firming op..ing exper-ience) of the equipment. he actuation logic is tested as part of the Engineered Safety Feature Actuation System (ESFAS) týe and equipment performance is monitored as part of the Inservice Testing Program.

Surveillance Requirement 4.5.2.i verifies the high and low pressur s fety i *ection valves listed in Table 4.5-1 will align to the required positions on an SIAS for rop r ECCS rformance. The safety injection valves have stops to position them properly so at fio is restricte a ruptured cold leg, ensuring that the other cold legs receive at least the equired inimum flow. The--8 Surveillance Requirement 4.5.2.j addresses perio ic inspection of t e containment sump to ensure that it is unrestricted and stays in proper perating condition. The 18 month frequelenyis

,clgractaaion and is eonirmied, by epiail xpcn.

Surveillance Requirement 4.5.2.k ve ies that the Shutdown Cooling (SDC) System open

'1 permissive interlock is OPERABL o ensure the SDC suction isolation valves are prevented from being remotely opened whe CS pressure is at or above the SDC suction design pressure of 300 psia. The suction piping f the SDC pumps (low pressure safety injection pumps) is the SDC component with the limi ng design pressure rating. The interlock provides assurance that double isolation of the SD ystem from the RCS is preserved whenever RCS pressure is at or above the design pressure. M90th frequency is based an 0140 44eed te pr40-- thiS survyeillance under-the conditions that apply durnt n uae The 18 month freguteney is also acceptable based en consider-atien ef the design rceliability (and confirmn prtn experience) of th equipffient.

MILLSTONE - UNIT 2 B 3/4 5-2c Amendment No. 4-5, -159, --8-5, 2-14, 2-1-6, 220, 2--2-3,226,2 -3

L=BDCR 05 N92 001 Februry_1, 2005nnc EMERGENCY CORE COOLING SYSTEMS BASES 3/4.5.5 TRISODIUM PHOSPHATE (TSP) (continued)

APPLICABILITY In MODES 1, 2, and 3, the RCS is at elevated temperature and pressure, providing an energy potential for a LOCA. The potential for a LOCA results in a need for the ability to control the pH of the recirculated coolant.

In MODES 4, 5, and 6, the potential for a LOCA is reduced or nonexistent, and TSP is not required.

ACTIONS If it is discovered that the TSP in the containment building sump is not within limits, action must be taken to restore the TSP to within limits. During plant operation the containment sump is not accessible and corrections may not be possible.

The completion time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is allowed for restoring the TSP within limits because 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is the same time allowed for restoration of other ECCS components.

If the TSP cannot be restored within limits within the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months completion time, the plant must be brought to a MODE in which the LCO does not apply. The specified completion times for reaching MODES 3 and 4 were chosen to allow reaching the specified conditions from full power in an orderly manner without challenging plant systems.

SURVEILLANCE REQUIREMENTS Surveillance Requirement 4.5.5.1 This periodic surveillance Periodic determination of the volume of TSP in co inment must be performed due to the possibility of leaking valves and components in t! containment building that could cause dissolution of the TSP during normal operation.. 4equency of 18 menth. is required to determine visually that a minimum of 282 cubic feet is contained in the TSP baskets. This requirement ensures that there is an adequate volume of TSP to adjust the pH of the post LOCA sump solution to a value _ 7.0.

The. periejdie verifieati n reuied . very 18 meaths, sinee aeeess to the T-SP baskets is only tag es,an d n ermal fuil eyelesare ech ediald f er1-8 m onth s. Op erati -n f easibl ed ur fing au exper-ience-bag shown thirs urvemillAnce fr:e'quency acceoptable due, to the- mar-gin in thet 1olume, of TSP placed int the ccntainment building.

MILLSTONE - UNIT 2 B 3/4 5-5 Amcnadmcnt N.

~Ar.ckjwledged by NRC letter- dated

-12/19/06

LDDCR 05 ?092 00 i FLbruar-y 10, 2005 EMERGENCY CORE COOLING SYSTEMS BASES 3/4.5.5 TRISODIUM PHOSPHATE (TSP) (continued)

Surveillance Requirement 4.5.5.2 Testing must be performed to ensure the solubility and buffering ability of the TSP after exposure to the containment environment. Passing this test verifies the TSP is active and provides assurance that the stored TSP will dissolve in borated water at postulated post-LOCA temperatures. This test is performed by submerging a sample of 0.6662 +/- 0.0266 grams of TSP from one of the baskets in containment in 250 +/- 10 milliliters of water at a boron concentration of 2482 +/- 20 ppm, and a temperature of 77 +/- 5'F. Without agitation, the solution is allowed to stand for four hours. The liquid is then decanted, mixed, and the pH measured. The pH must be > 7.0.

The TSP sample weight is based on the minimum required TSP mass of 12,042 pounds, which at the manufactured density corresponds to the minimum volume of 223 ft3 (The minimum Technical Specification requirement of 282 ft 3 is based on 223 ft 3 of TSP for boric acid neutralization and 59 ft 3 of TSP for neutralization of hydrochloric and nitric acids.), and the maximum sump water volume (at 77°F) following a LOCA of 2,046,441 liters, normalized to buffer a 250 +/- 10 milliliter sample. The boron concentration of the test water is representative of the maximum possible concentration in the sump following a LOCA. Agitation of the test solution is prohibited during TSP dissolution since an adequate standard for the agitation intensity cannot be specified. The dissolution time of four hours is necessary to allow time for the dissolved TSP to naturally diffuse through the sample solution. In the containment sump following a LOCA, rapid mixing will occur, significantly decreasing the actual amount of time before the required pH is achieved. The solution is decanted after the four hour period to remove any undissolved TSP prior to mixing and pH measurement. Mixing is necessary for proper operation of the pH instrument.

Inet2a MILLSTONE - UNIT 2 B 3/4 5-6 Amendmcnt Nc.

Acknowledged by NRC letter dated

+1 1-91/'&

BDDCR 04 NIP2 016 FebiuaIy 24, 2005 CONTAINMENT SYSTEMS BASES 3/4.6.2 DEPRESSURIZATION AND COOLING SYSTEMS 3/4.6.2.1 CONTAINMENT SPRAY AND COOLING SYSTEMS The OPERABILITY of the containment spray system ensures that containment depressurization and cooling capability will be available in the event of a LOCA. The pressure reduction and resultant lower containment leakage rate are consistent with the assumptions used in the accident analyses.

The OPERABILITY of the containment cooling system ensures that 1) the containment air temperature will be maintained within limits during normal operation, and 2) adequate heat removal capacity is available when operated in conjunction with the containment spray system during post-LOCA conditions.

To be OPERABLE, the two trains of the containment spray system shall be capable of taking a suction from the refueling water storage tank on a containment spray actuation signal and automatically transferring suction to the containment sump on a sump recirculation actuation signal. Each containment spray train flow path from the containment sump shall be via an OPERABLE shutdown cooling heat exchanger.

The containment cooling system consists of two containment cooling trains. Each containment cooling train has two containment air recirculation and cooling units. For the purpose of applying the appropriate ACTION statement, the loss of a single containment air recirculation and cooling unit will make the respective containment cooling train inoperable.

Either the containment spray system or the containment cooling system is sufficient to mitigate a loss of coolant accident. The containment spray system is more effective than the containment cooling system in reducing the temperature of superheated steam inside containment following a main steam line break. Because of this, the containment spray system is required to mitigate a main steam line break accident inside containment. In addition, the containment spray system provides a mechanism for removing iodine from the containment atmosphere. Therefore, at least one train of containment spray is required to be OPERABLE when pressurizer pressure is

_>1750 psia, and the allowed outage time for one train of containment spray reflects the dual function of containment spray for heat removal and iodine removal.

Surveillance Requirement 4.6.2... 1.a verifies the correct alignment for manual, power operated, and automatic valves in the Containment Spray System flow paths to provide assurance that the proper flow paths will exist for containment spray operation. This surveillance does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve that receives an actuation signal is allowed to be in a nonaccident position provided the valve automatically repositions within the proper stroke time. This surveillance does not require any testing or valve manipulation. Rather, it involves verification that those valves capable of being mispositioned are in the correct position. *h, 31 day freqtt-,y is appropriate b the... alve a ,perated itt*d.

MILLSTONE - UNIT 2 V I 2w B 3/4 6-3 I nt 2a]Adcknowiledged se Amendment No. 2-5, 6-, 2-1-0, 24-5, 22-8, 2-36, b283, by NP.C letter dated 6/2 8/05

Januar-y 12, 2012 L=BDCR 12 N4P2 001 CONTAINMENT SYSTEMS BASES 3/4.6.2.1 CONTAINMENT SPRAY AND COOLING SYSTEMS (Continued)

Surveillance Requirement 4.6.2.1.1 .b, which addresses periodic surveillance testing of the containment spray pumps to detect gross degradation caused by impeller structural damage or other hydraulic component problems, is required by the ASME OM Code. This type of testing may be accomplished by measuring the pump developed head at only one point of the pump characteristic curve. This verifies both that the measured performance is within an acceptable tolerance of the original pump baseline performance and that the performance at the test flow is greater than or equal to the performance assumed in the unit safety analysis. The surveillance requirements are specified in the Inservice Testing Program. The ASME OM Code provides the activities and frequencies necessary to satisfy the requirements. Insert 2b Surveillance Requirements 4.6.2.1.1 .c and 4.6.2. 1.1 .d demonstrate that each a tomatic containment spray valve actuates to the required position on an actual or simulated a tuation signal (CSAS or SRAS), and that each containment spray pump starts on receipt of n actual or simulated actuation signal (CSAS). This surveillance is not required for valves th are locked, sealed, or otherwise secured in the required position under administrative controls. he 1 imn frequtency is based afn the need to per-form these stwveillanees uinder- the conditionts that apply during a plant outage and the petential fer-unplanned tr-ansicnts if the sufveillances were per-formed with the reaeter-at power. The 18 menth frequeney is also acceeptafble baSed on consideration of the design reliability (and confirmiing oper-ating exper-iencee) of the equ ipnt The actuation logic is tested as part of the Engineered Safety Feature Actuation System (ESFAS) testing, and equipment performance is monitored as part of the Inservice Testing Program.

Surveillance Requirement 4.6.2. 1.1 .e requires verification that each spray nozzle is unobstructed following maintenance that could cause nozzle blockage. Normal plant operation and maintenance activities are not expected to trigger performance of this surveillance requirement. However, activities, such as an inadvertent spray actuation that causes fluid flow through the nozzles, a major configuration change, or a loss of foreign material control when working within the respective system boundary may require surveillance performance. An

.... ..... . .-1 *4-. .. .., A * +1...

..'L, . . ... .. 11 .... ..

4'1.,. .. ,-*÷2-8-3,1, evaluation, based on the specific situation, will determine the appropriate method (e.g., visual inspection, air or smoke flow test) to verify' no nozzle obstruction.

Surveillance Requirement 4.6-.2.12a demonstrates that each containment air recirculation and cooling unit can be operated in slow speed for > 15 minutes to ensure OPERABILITY and that all associated controls are functioning properly. It also ensures fan or motor failure can be detected and corrective action taken. The 31 day fr-equency considers the knewn reliability of the fan units and eontroels, the Iv ranr udac available, and the low proebability of a significant MILLSTONE - UNIT 2 B 3/4 6-3a Amendment No. 2-4-0, 244-, 2-36, 27-,

LBDCR 09-MP2-O, 1 jun- 30, 2009--

CONTAINMENT SYSTEMS BASES 3/4.6.2.1 CONTAINMENT SPRAY AND COOLING SYSTEMS (Continued)

Surveillance Requirement 4.6.2.1..2.b demonstrates a cooling water flow rate of> 500 gpm to each containment air recirculation and cooling unit to provide assurance a cooling water flow path through the cooling unit is available. ite 3,1 day ,,,,,ene ..... .......... r the know reliability of the. ,Goolingw *,at-r syste,¢* the t-.... N --

A'- A..--A. .. ..- llIn __1-L 1.. .. _l. 1 ,

of a s;,,ng r.ni an

.... Aat., nofn fi.. w I.. .. M

... I*.,, ..... . e1

.. Thi-s; -eI..... ene.. bee sh ...w . . be. . ..... .....

thf tig ep.. ...- '-vn......... ý ý nsert 7-- 2a n..r Surveillance Requirement 4.6.2.1 .2.c demonstrates that each contal nt air recirculation and cooling unit starts on receipt of an actual or simulated actuation signal (SIA ')'fhe 1.8 month freq"ueny i based on the need to perform these surveillancce under the conditions that.apply during a plant outage and the potential for unplanned transients if the..suz VillaIe W performed ,,ith the -reactor-at power. f he 18 month fr.,un.y is a,, acceptable based on ccnsider-ation of the design r-eliability (and confirming eper-atg cxprin) of the equipment.

The actuation logic is tested as part of the Engineered Safety Feature Actuation System (ESFAS) testing, and equipment performance is monitored as part of the Inservice Testing Program.

3/4.6.3 CONTAINMENT ISOLATION VALVES The Technical Requirements Manual contains the list of containment isolation valves (except the containment air lock and equipment hatch). Any changes to this list will be reviewed under 10CFR50.59 and approved by the committee(s) as described in the QAP Topical Report.

The OPERABILITY of the containment isolation valves ensures that the containment atmosphere will be isolated from the outside environment in the event of a release of radioactive material to the containment atmosphere or pressurization of the containment. Containment isolation within the time limits specified ensures that the release of radioactive material to the environment will be consistent with the assumptions used in the analyses for a LOCA.

The containment isolation valves are used to close all fluid (liquid and gas) penetrations not required for operation of the engineered safety feature systems, to prevent the leakage of radioactive materials to the environment. The fluid penetrations which may require isolation after an accident are categorized as Type P, 0, or N. The penetration types for each containment isolation valve are listed in FSAR Table 5.2-11, Containment Structure Isolation Valve Information.

Type P penetrations are lines that connect to the reactor coolant pressure boundary (Criterion 55 of 10CFR50, Appendix A). These lines are provided with two containment isolation valves, one inside containment, and one outside containment.

Type 0 penetrations are lines that are open to the containment internal atmosphere (Criterion 56 of 10CFR50, Appendix A). These lines are provided with two containment isolation valves, one inside containment, and one outside containment.

MILLSTONE - UNIT 2 B 3/4 6-3b Amendment No. 210, 24-5, 2-36, 2-7-8, 283,

LtJtJiji U4-MF2-1 I b FlbUaIny 24, 2005 CONTAINMENT SYSTEMS BASES 3/4.6.3 CONTAINMENT ISOLATION VALVES (continued)

Type N penetrations are lines that neither connect to the reactor coolant pressure boundary nor are open to the containment internal atmosphere, but do form a closed system within the containment structure (Criterion 57 of 10CFR50, Appendix A). These lines are provided with single containment isolation valves outside containment. These valves are either remotely operated or locked closed manual valves.

With one or more penetration flow paths with one containment isolation valve inoperable, the inoperable valve must be restored to OPERABLE status or the affected penetration flow path must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange. A check valve may not be used to isolate the affected penetration.

If the containment isolation valve on a closed system becomes inoperable, the remaining barrier is a closed system since a closed system is an acceptable alternative to an automatic valve.

However, ACTIONS must still be taken to meet Technical Specification ACTION 3.6.3.1 .d and k-the valve, not normally considered as a containment isolation valve, and closest to the containment wall should be put into the closed position. No leak testing of the alternate valve is necessary to satisfy the ACTION statement. Placing the manual valve in the closed position ,

sufficiently deactivates the penetration for Technical Specification compliance. Closed system isolation valves applicable to Technical Specification ACTION 3.6.3.1 .d are included in FSAR Table 5.2-11, and are the isolation valves for those penetrations credited as General Design Criteria 57, (Type N penetrations). The specified time (i.e., 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months ) of Technical Specification ACTION 3.6.3. l.d is reasonable, considering the relative stability of the closed system (hence, reliability) to act as a penetration isolation boundary and the relative importance of supporting containment OPERABILITY during MODES 1, 2, 3, and 4. In the event the affected penetration is isolated in accordance with 3.6.3.1 .d, the affected penetration flow path must be verified to be isolated on a periodic basis, (Surveillance Requirement 4.6.1.1 .a). This is necessary to assure leak tightness of containment and that containment penetrations requiring isolation following an accident are isolate/ The freq,

,. of-on"- per 31 days in this srveillane, for v.ri. ying that eaeh affccWed fc1iltow path is isolated is onsiderirng the valves are aperated eprpit under admI atiVc nr an. tho probability eftheir misalignment is low.

Insert 2a *For the purposes of meeting this LCO, neither the containment isolation valve, nor any alternate valve on a closed system have a leakage limit associated with valve OPERABILITY.

MILLSTONE - UNIT 2 B 3/4 6-3c Amendment No. 24-0, 2-4-5, 236, 2-7-8, 283, Acknowledged by NRC let*r. dated 6/28,/05

LBDGR 13" 1P2 013 October- 1, 2013 CONTAINMENT SYSTEMS BASES 3/4.6.4 COMBUSTIBLE GAS CONTROL Surveillance Requirement 4.6.3.1 .b demonstrate that each automatic containment Insert 2a isolation valve actuates to the isolation position on an actual or simulated containment isol tion signal [containment isolation actuation signal (CIAS) or containment high radiation actuati n signal (containment purge valves only)]. This surveillance is not required for valves that ar locked, sealed, or otherwise secured in the required position under administrative controls.

18 month frequency is based on the need to per-form these surveillances Under- the conditionis that apply dur-ing a plant eutage and the potential for-unplanned Ifansients if the surveillancee was per-formfed with the r-eactor at power. The 18 month frequency is also acceptable basedn eonsider-ation of the design reliability (and confirmn orting experienee) of the equipment.

The actuation logic is tested as part of the Engineered Safety Feature Actuation System (ESFAS) testing, and equipment performance is monitored as part of the Inservice Testing Program.

The OPERABILITY of the equipment and systems required for control of hydrogen gas ensures that this equipment will be available to maintain the hydrogen concentration within containment below its flammable limit during post-LOCA conditions.

The post-incident recirculation systems are provided to ensure adequate mixing of the containment atmosphere following a LOCA. This mixing action will prevent localized accumulations of hydrogen from exceeding the flammable limit.

MILLSTONE - UNIT 2 B 3/4 6-4 Amendment No.-2--3-,

Aekwedggedby NRC!er- dated 12/1-9/06

LBDCRO09 M4P2 012 Aprli 13,2"4-0 CONTAINMENT SYSTEMS BASES 3/4.6.5 SECONDARY CONTAINMENT 3/4.6.5.1 ENCLOSURE BUILDING FILTRATION SYSTEM The OPERABILITY of the Enclosure Building Filtration System ensures that containment leakage occurring during LOCA conditions into the annulus will be filtered through the HEPA filters and charcoal adsorber trains prior to discharge to the atmosphere. This requirement is necessary to meet the assumptions used in the accident analyses and limit the SITE BOUNDARY radiation doses to within the limits of 10 CFR 50.67 during LOCA conditions.

The laboratory testing requirement for the charcoal sample to have a removal efficiency of

_ 95% is more conservative than the elemental and organic iodine removal efficiencies of 90%

and 70%, respectively, assumed in the DBA analyses for the EBFS charcoal adsorbers in the Millstone Unit 2 Final Safety Analysis Report. A removal efficiency acceptance criteria of> 95%

will ensure the charcoal has the capability to perform its intended safety function throughout the length of an operating cycle.

Surveillance Requirement 4.6.5.1 .b.1 dictates the test frequency, method and acceptance criteria for the EBFS trains (cleanup trains). These criteria all originate in the Regulatory Position sections of Regulatory Guide 1.52, Rev. 2, March 1978 as discussed below:

Section C.5.a requires a visual inspection of the cleanup system be made before the following tests, in accordance with the provisions of section 5 of ANSI N510-1975:

" in-place air flow distribution test Ithe frequency specified in the Surveillance

" DOP test Frequency Control/Pgram

" activated carbon adsorber section 1 test Section C.5.c requires the in-place ioctyl phthalate (DOP) test for EPA filters to eenfeomatto section 10 of ANSI N510-19750g'he HEPA filters should be teste,fin place (1) initially, (2) any least onec per 18 m."c.nth*. t~hereafter, and (3) following painting, ire, or chemical release in less ventilation zone communicating with the system. The testing/i to confirm a penetration of than or equal to 1%* at rated flow.

Section C.5.d requires the charcoal adsorber section to/le leak tested with a gaseous halogenated bypass hydrocarbon refrigerant, in accordance with section ]2of ANSI N5 10-1975 to ensure thatshould 4 leakage through the adsorber section is less than o qu~al to 1%.** Adsorber leak testing be conducted (1) initially, (2) at 'caot on'ce per 18 ."onh.s.

m t.hereafter, (3) following removal of an adsorber sample for laboratory testing if the integrity of the adsorber

Means that the HEPA filter will allow passage of less than or equal to 1% of the test -f concentration injected at the filter inlet from a standard DOP concentration injection.

- Means that the charcoal adsorber sections will allow passage of less than or equal to 1% of the injected test concentration around the charcoal adsorber sections.

MILLSTONE - UNIT 2 B 3/4 6-5 Amendment No. 2-N,

Novembe 10, 2005 LBDCGR 04 NMP2 013 3/4.7 PLANT SYSTEMS BASES 3/4.7.1.2 AUXILIARY FEEDWATER PUMPS (Continued)

A Note limits the applicability of the inoperable equipment condition b. to when the unit has not entered MODE 2 following a REFUELING. Required ACTION b. allows one auxiliary feedwater pump to be inoperable for 7 days vice the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months allowed outage time in required ACTION c. This longer allowed outage time is based on the reduced decay heat following REFUELING and prior to the reactor being critical.

With one of the auxiliary feedwater pumps inoperable in MODE 1, 2, or 3 for reasons other than ACTION a. or b., ACTION must be taken to restore the inoperable equipment to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This includes the loss of both steam supply lines to the turbine-driven auxiliary feedwater pump. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months allowed outage time is reasonable, based on redundant capabilities afforded by the auxiliary feedwater system, time needed for repairs, and the low probability of a DBA occurring during this time period. Two auxiliary feedwater pumps and flow paths remain to supply feedwater to the steam generators.

If all three AFW pumps are inoperable in MODE 1, 2, or 3, the unit is in a seriously degraded condition with no safety related means for conducting a cooldown, and only limited means for conducting a cooldown with non-safety related equipment. In such a condition, the unit should not be perturbed by any action, including a power change that might result in a trip.

The seriousness of this condition requires that action be started immediately to restore one AFW pump to OPERABLE status. Required ACTION e. is modified by a Note indicating that all required MODE changes or power reductions are suspended until one AFW pump is restored to OPERABLE status. In this case, LCO 3.0.3 is not applicable because it could force the unit into a less safe condition. .. , 1*I~eriodicl During quai4erly surveillance testing of the turbine driven AFW pump, valve 2-CN-27A is closed and valve 2-CN-28 is opened to prevent overheating the water being circulated. In this configuration, the suction of the turbine driven AFW pump is aligned to the Condensate Storage Tank via the motor driven AFW pump suction flow path, and the pump minimum flow is directed to the Condensate Storage Tank by the turbine driven AFW pump suction path upstream of 2-CN-27A in the reverse direction. During this surveillance, the suction path to the motor driven AFW pump suction path remains OPERABLE, and the turbine driven AFW suction path is inoperable. In this situation, the ACTION requirements of Technical Specification 3.7.1.2 for one AFW pump are applicable.

Insert 2a MILLSTONE - UNIT 2 B 3/4 7-2c Amendment No. 283,

June i9, 2-007 LBDCR 07 MP2 014 3/4.7 PLANT SYSTEMS BASES 3/4.7.1.2 AUXILIARY FEEDWATER PUMPS (Continued)

Surveillance Requirement 4.7.1.2.a verifies the correct alignment for manual, power operated, and automatic valves in the Auxiliary Feedwater (AFW) System flow paths (water and steam) to provide assurance that the proper flow paths will exist for AFW operation. This surveillance does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve that receives an actuation signal is allowed to be in a nonaccident position provided the valve automatically repositions within the proper stroke time. This surveillance does not require any testing or valve manipulation. Rather, it involves verification that those valves capable of being m lsp o sit o n e d are in th e c o rrect p o sit o n . h e. 3 ,1 d ay fr,, u e..... .b .e . . s . th..e .v a..lv es..

Surveillance Requirement 4.7..12a. , w ic addresses periodic surveillance testing of the AFW pumps to detect gross degradation caused by impeller structural damage or other hydraulic component problems, is required by the ASME Code for Operations and Maintenance of Nuclear Power Plants (ASME OM Code). This type of testing may be accomplished by measuring the pump developed head at only one point of the pump characteristic curve. This verifies both that

'1 the measured performance is within an acceptable tolerance of the original pump baseline performance and that the performance at the test flow is greater than or equal to the performance assumed in the unit safety analysis. The surveillance requirements are specified in the Inservice Testing Program. The ASME OM Code provides the activities and frequencies necessary to ~1-satisfy the requirements. This surveillance is modified to indicate that the test can be deferred for the steam driven AFW pump until suitable plant conditions are established. This deferral is required because steam pressure is not sufficient to perform the test until after MODE 3 is entered. Once the unit reaches 800 psig, 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months would be allowed for completing the surveillance. However, the test, if required, must be performed prior to entering MODE 2.

Surveillance Requirements 4.7.1.2.c and 4.7.1.2.d demonstrate that each automatic AFW valve actuates to the required position on an actual or simulated actuation signal (AFWAS) and that each AFW pump starts on receipt of an actual or simulated actuation signal (AFWAS). This surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative contro s. c 18 month fcqucncy is based o. the need to perform eperating exper-ience) ef the equipment. Th actuation logic is tested as part of the Engineered Safety Feature Actuation System (ESFAS) tes ing, and equipment performance is monitored as part of the Inservice Testing Program. These su eillances do not apply to the steam driven AFW pump and associated valves which are not autom tically actuated.

MILLSTONE - UNIT 2 B 3/4 7-2d Insert 2a .A.m.ndm .

PLANT SYSTEMS BASES 3/4.7.3 REACTOR BUILDING CLOSED COOLING WATER SYSTEM (Continued)

It is acceptable to operate with the RBCCW pump minimum flow valves (2-RB-107A, 2-RB-107B, 2-RB-107C), RBCCW pump sample valves (2-RB-56A, 2-RB-56B, and 2-RB-56C),

and the RBCCW pump radiation monitor stop valves (2-RB-39, 2-RB-41,and 2-RB-43) open. An active single failure will not adversely impact both RBCCW loops with these valves open. In addition, protection against a passive single failure after the initiation of post-loss of coolant accident long term cooling is achieved by manually closing these accessible valves, as directed by the emergency operating procedures. In addition, operation with RBCCW chemical addition valves (2-RB-50A and 2-RB-50B) open during chemical addition evolutions is acceptable since these normally closed valves are opened to add chemicals to the RBCCW and then closed as directed by normal operating procedures. Therefore, operation with these valves open does not affect OPERABILITY of the RBCCW loops.

Surveillance Requirement 4.7.3.1 .a verifies the correct alignment for manual, power operated, and automatic valves in the RBCCW System flow paths to provide assurance that the proper flow paths exist for RBCCW operation. This surveillance does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve that receives an actuation signal is allowed to be in a nonaccident position provided the valve automatically repositions within the proper stroke time. This surveillance does not require any testing or valve manipulation. Rather, it involves verification that those valves capable of being mispositioned are in the correct position.

Thec 31 day frqtee e~ beat the valves are operated tinder-pr-eeedur-al eentr-el and-an imprnnoper ialhe position would only affect a single, train. his frequen y has been Rhown to be, a.cceptable

. h.r."ugh "crtm. nsert 2aI Surveillance Requirements 4.7.3. L.b and 4.7.3. 1.c demonstrate that each automatic RBCCW valve actuates to the required position on an actual or simulated actuation signal and that each RBCCW pump starts on receipt of an actual or simulated actuation signal. This surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls. 8 month ,t .. b on......... v ........ e e~per;,eae f t~he equipment.. The actuation'gic is tested as part of the Engineered Safety Feature Actuation System (ESFAS) testing, and *,uipment performance is monitored as part of the Inservice Testing Program.

3/4.7.4 SERVICE WATER SYSTEM The OPERABILITY of the Service Water (SW) System ensures that sufficient cooling capacity is available for continued operation of vital components and Engineered Safety Feature equipment during normal and accident conditions. The redundant cooling capacity of this system, assuming a single failure, is consistent with the assumptions used in the accident analyses.

MILLSTONE - UNIT 2 B 3/4 7-3c Amendment No. 249, 223,2-2-6,236, 2-3-g, ILBDGR 13 MP2 017

-etebef46 16-201 PLANT SYSTEMS BASES 3/4.7.4 SERVICE WATER SYSTEM (Continued) determined to be inoperable should be the loop that results in the most adverse plant configuration with respect to the availability of accident mitigation equipment. Restoration of loop independence within the time constraints of the allowed outage time is required, or a plant shutdown is necessary.

Branch lines are supplied to isolation valves in the intake for lubrication to the circulating water pump bearings (2-SW-298 and 2-SW-299), and alternate supply connections (2-SW-84A, and 2-SW-84B). The flow restricting orifices in these lines ensure that safety related loads continue to receive minimum required flow during a LOCA (in which the lines remain intact), or during a seismic event (when the lines break) even with the valves open. Therefore, operation with these valves open does not affect OPERABILITY of the SW loops.

Surveillance Requirement 4.7.4.1 .a verifies the correct alignment for manual, power operated, and automatic valves in the Service Water (SW) System flow paths to provide assurance that the proper flow paths exist for SW operation. This surveillance does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve that receives an actuation signal is allowed to be in a nonaccident position provided the valve automatically repositions within the proper stroke time. This surveillance does not require any testing or valve manipulation. Rather, it involves verification that those valves capable of being mispositioned are in the correct position.

The 31 day frequency i apprpi because the valves are operated under-pro..edur-al

. ntr..l and nimprpr valve pesiti w"rn .uldaff.et a single.nly train. This f.equeney has been shown to be acceptable thoutgh opeatn eprence.

Surveillance Requirements 4.7.4. 1.b and 4.7.4. L.c demonstrate that each automatic SW valve actuates to the required position on an actual or simulated actuation signal and that each SW pump starts on receipt of an actual or simulated actuation signal. This surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls. The 18 month frequen.y is based en the need to perf-o...m these survcillanccs under-the eonditions that apply during a plant outage and the potcntial for-unplanned tr-ansients if the sunvcillanccs were pcr-fermed with the r-eaetor at power. The 18 month frequency is also acceptable based on consider-ation of the design reliability (and confirminfig ope'atin

...... ;...of the equipment.. ke actuation logic is tested as part of the Engineered Safety Feature Actuation System (ESFA testing, and equipment performance is monitored as part of the Inservice Testing Program.

3/4.7.5 DELETED 3/4. D2bE MILLSTONE - UNIT 2 B 3/4 7-4 Amendment No. 272-3, 2-36, 2-7-2, 2-7-3,

LBDCGR 09 N4P2 012 A 20*-l PLANT vS Pthe frequency specified in the Surveillance BASES //--Frequency Control Program 3/4.7.6 CONTROL ZOM EMERGENCY VENTIL ION SYSTEM (Continued) e Section C.5.c r uires/0the in-place Dioctyl phthal e (DOP) test for HEPA filters to conform to section 10 ýANSI N510-1975. The HEPA filte s should be tested in place (1) initially, (2) at lcast onco pcr 18 mcnths thhcrcaftcr, and (3) fo owing painting, fire, or chemical release in any ventilation zone communicating with the sy em. The testing is to confirm a penetration of less than or equal to 1%* at rated flow.

Section C.5.d requires the charcoal ad rber section to be leak tested with a gaseous halogenated hydrocarbon refrigerant, in accordan e with section 12 of ANSI N510-1975 to ensure that bypass leakage through the adsorber secti is less than or equal to 1%.** Adsorber leak testing should 4-be conducted (1) initially, (2) at Ica..cnc.cr- 18 mr nth- thereafter-, (3) following removal of an adsorber sample for laboratory testing if the integrity of the adsorber section is affected, and (4) following painting, fire, or chemical release in any ventilation zone communicating with the The ACTION requirements to immediately suspend various activities (CORE ALTERATIONS, irradiated fuel movement, etc.) do not preclude completion of the movement of a component to a safe position.

Technical Specification 3.7.6.1 provides the OPERABILITY requirements for the Control Room Emergency Ventilation Trains. If a Control Room Emergency Ventilation Train emergency power source or normal power source becomes inoperable in MODES 1, 2, 3, or 4 the requirements of Technical Specification 3.0.5 apply in determining the OPERABILITY of the affected Control Room Emergency Ventilation Train. If a Control Room Emergency Ventilation Train emergency power source or normal power source becomes inoperable in MODES 5 or 6 the guidance provided by Note "**" of this specification applies in determining the OPERABILITY of the affected Control Room Emergency Ventilation Train. If a Control Room Emergency Ventilation Train emergency power source or normal power source becomes inoperable while not in MODES 1, 2, 3, 4, 5, or 6 the requirements of Technical Specification 3.0.5 apply in determining the OPERABILITY of the affected Control Room Emergency Ventilation Train.

Means that the HEPA filter will allow passage of less than or equal to 1% of the test 4-concentration injection at the filter inlet from a standard DOP concentration injection.

- Means that the charcoal adsorber sections will allow passage of less than or equal to 1% of the injected test concentration around the charcoal adsorber section.

MILLSTONE - UNIT 2 B 3/4 7-4d Amendmen

LBE)DR 13 MP2 004 Maty-2,20-l-PLANT SYSTEMS BASES 3/4.7.11 ULTIMATE HEAT SINK (Continued)

LCO The UHS is required to be OPERABLE and is considered OPERABLE if it contains a sufficient volume of water at or below the maximum temperature that would allow the SW System to operate for at least 30 days following the design basis LOCA without the loss of net positive suction head (NPSH), and without exceeding the maximum design temperature of the equipment served by the SW System. To meet this condition, the UHS temperature should not exceed 80'F during normal unit operation.

While the use of any supply side SW temperature indication is adequate to ensure compliance with the analysis assumptions, precision instruments installed at the inlet to the reactor building closed cooling water (RBCCW) heat exchangers will normally be used.

Therefore, instrument uncertainty need not be factored into the surveillance acceptance criteria.

All in-service instruments must be within the limit. If all of the precision instruments are out of service, alternative instruments that measure SW supply side temperature will be used. In this case, an appropriate instrument uncertainty will be subtracted from the acceptance criteria.

Since Long Island Sound temperature changes relatively slowly and in a predictable fashion according to the tides, it is acceptable to monitor this temperature df*ily when there is ample (>5oF) margin to the limit. When within 5°F of the limit, the tempera re shall be monitored every 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to ensure that tidal variations are appropriately cap red.

APPLICABILITY the frequency specified in the SurveillanceL

Frequency Control Programl In MODES 1, 2, 3, and 4, the UHS is required to support the OPERABILITY of the equipment serviced by the UHS and required to be OPERABLE in these MODES.

In MODE 5 or 6, the OPERABILITY requirements of the UHS are determined by the systems it supports.

ACTION If the UHS is inoperable, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

The allowed outage times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

MILLSTONE - UNIT 2 B 3/4 7-8

LBDDCR 07 N92 009 Miarch 29, 2001 3/4.8 ELECTRICAL POWER SYSTEMS BASES The 31 day ftcgucney for SR 42is eensist\nt with standard industry guid .

SR 4.8.1.1.2.a.3 This surveillance verifies that the diesel generators are capable of synchronizing wit the offsite electrical system and accepting loads greater than or equal to the equivalent of the maximum expected accident loads. A minimum run time of 60 minutes is required to stabili engine temperatures, while minimizing the time that the diesel generator is connected to the offsite source. Although no power factor requirements are established by this surveillance, th diesel generator is normally operated at a power factor between 0.8 lagging and 1.0. The 0.8 value is the design rating of the machine, while 1.0 is an operational limitation.

This surveillance is modified by five Notes. Note I indicates that diesel engine runs for Insert 2a this surveillance may include gradual loading, as recommended by the manufacturer, so that mechanical stress and wear on the diesel engine are minimized. Note 2 states that momentary transients because of changing bus loads do not invalidate this test. Similarly, momentary po r factor transients above the limit will not invalidate the test. Note 3 indicates that this surveilla ce should be conducted on only one diesel generator at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations. Note 4 stipulates a prerequ site requirement for performance of this surveillance. A successful diesel generator start must precede this test to credit satisfactory performance. Note 5 states that SR 4.8.1.1.2.d, a mor rigorous test, may be performed in lieu of 4.8.1.1.2.a.

The 31t day fiIquenIy fbi SR 4.S. i. ...2.a.3 is c* iste with standard industry guidel.

SR 4.8. 1.1 .2 b. at the frequency specified in the Surveillance Frequency Control Program Microbiological fouling is a major cause of fuel oil degradatio . There are numerous bacteria that can grow in fuel oil and cause fouling, but all must hav water environment in order to survive. Removal of water from the three fuel storage tanks -nee eyef' 92 days eliminates the necessary environment for bacterial survival. This is the most effective means of controlling microbiological fouling. In addition, it eliminates the potential for water entrainment in the fuel oil during EDG operation. Water may come from any of several sources, including condensation, rain water, contaminated fuel oil, and from breakdown of the fuel oil by bacteria.

Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. This surveillance is for preventative maintenance. The presence of water does not necessarily represent failure of this surveillance provided the accumulated water is removed during performance of the surveillance.

MILLSTONE - UNIT 2 B 3/4 8-6 Amendment No. 2-7-7,

March 29, 200O7 3/4.8 ELECTRICAL POWER SYSTEMS BASES determination of total particulate concentration in the fuel oil and has a limit of 10 mg/l. It is acceptable to obtain a field sample for subsequent laboratory testing in lieu of field testing.

The frequency of this test takes into consideration fuel oil degradation trends that indicate that particulate concentration is unlikely to change significantly between surveillance intervals.

SR. 4.8.1.1.2.c.2 Under accident and loss of offsite power conditions, loads are sequentially connected to the bus by the automatic load sequencer. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading of the diesel generators due to high motor starting currents. The load sequence time interval tolerances ensure that sufficient time exists for the diesel generator to restore frequency and voltage prior to applying the next load and that safety analysis assumptions regarding Engineered Safety Features (ESF) equipment time delays are not violated.

.n.sid taking into Thc 18 m, nth frqu*.. y is based eo ngin..rin. judgment, e..ation unit conditions required to performn the sur,rcillance, and is intended to be eansistent with eyipected fuel cycle lengths. Opcrtn ccicnce has shown that these comnponents tistally pams the surn'cillaacc when per-fe-nnmcd at t.hc 18 month fr-equcney. Thcrferc , the frequeney is acceptable from a reliability standpoin.t. Insert 2a This surveillance is modified by a Note. The reason for the Note is that performing the surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. This restriction from normally performing the surveillance in MODE 1, 2, 3, or 4 is further amplified to allow the surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g. post work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is maintained or enhanced. This assessment shall, as a minimum, consider the potential outcomes and transients associated with a failed surveillance, a successful surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and start up to determine that plant safety is maintained or enhanced when the surveillance is performed in MODE 1, 2, 3, or 4. Risk insights or deterministic methods may be used for this assessment.

MILLSTONE - UNIT 2 B 3/4 8-8 Amendment No. 2-77, *,

LDDCR 07 MP2 009 Marceh 29, 2007 3/4.8 ELECTRICAL POWER SYSTEMS BASES SR 4.8.1.3.2.c.3 Each diesel generator is provided with an engine overspeed trip to prevent damage to the engine. Recovery from the transient caused by the loss of a large load could cause diesel engine overspeed, which, if excessive, might result in a trip of the engine. This surveillance demonstrates the diesel generator load response characteristics and capability to reject the largest single load without exceeding a predetermined frequency limit. The single largest load for each diesel generator is identified in the FSAR (Tables 8.3-2 and 8.3-3).

This surveillance may be accomplished by either:

a. Tripping the diesel generator output breaker with the diesel generator carrying greater than or equal to its associated single largest post-accident load while paralleled to offsite power or while solely supplying the bus; or

b. Tripping the equivalent of the single largest post-accident load with the diesel generator solely supplying the bus.

The time, voltage, and frequency tolerances specified in this surveillance are based on the response during load sequence intervals. The 2.2 seconds specified is equal to 40% of the 5.5 second load sequence interval associated with sequencing of the largest load (Safety Guide 9).

The voltage and frequency specified are consistent with the design range of the equipment powered by the diesel generator. SR 4.8.1.1 .2.c.3.a corresponds to the maximum frequency excursion, while SR 4.8.l.1.2.c.3.b and SR 4.8.1.1.2.c.3.c are steady state voltage and frequency values to which the system must recover following load rejection.

T'he 18 month frequency is b-ased-on engineer-ing judgment, taking into coQnsid-eration uit eenditions required to pcr-form the surveillance, -And-is in-tenld-ed to be co-nsisteant w.ith expocted fuel eyle lengths.E .i CCiertee has showni that these eomponents ttsually pass the survcillancce when performcd- Mt t~he 18 manth froqueney. Therefore, the frequeoncy is tteeeptabl ficinit*h aibihlty taandpuiLnl. Insert 2 This surveillance is modified by a Note to ensure that the diesel generator is tested under load conditions that are as close to design basis conditions as practical. When synchronized with offsite power, testing should be performed at a power factor of*< 0.9 lagging. This power factor is representative of the inductive loading a diesel generator would see based on the motor rating of the single largest load. It is within the adjustment capability of the Control Room Operator based on the use of reactive load indication to establish the desired power factor. Under certain conditions, however, the note allows the surveillance to be conducted at a power factor other than

< 0.9. These conditions occur when grid voltage is high, and the additional field excitation needed to get the power factor to < 0.9 results in voltages on the emergency buses that are too MILLSTONE - UNIT 2 B 3/4 8-9 Amendment No. 2-7-7, -

LBDCeR 07 MP2 009 March 29, 2-00/

3/4.8 ELECTRICAL POWER SYSTEMS BASES high. Under these conditions, the power factor should be maintained as close as practicable to 0.9 while still maintaining acceptable voltage limits on the emergency buses. In other circumstances, the grid voltage may be such that the diesel generator excitation levels needed to obtain a power factor of 0.9 may not cause unacceptable voltages on the emergency buses, but the excitation levels are in excess of those recommended for the diesel generator. In such cases, the power factor shall be maintained as close as practicable to 0.9 lagging without exceeding the diesel generator excitation limits.

SR 4.8.1.1.2.c.4 This surveillance demonstrates the diesel generator capability to reject a rated load without overspeed tripping. A diesel generator rated load rejection may occur because of a system fault or inadvertent breaker tripping. This surveillance ensures proper engine generator load response under the simulated test conditions. This test simulates the loss of the total connected load that the diesel generator experiences following a rated load rejection and verifies that the diesel generator will not trip upon loss of the load. While the diesel generator is not expected to experience this transient during an event, this response ensures that the diesel generator is not degraded for future application, including reconnection to the bus if the trip initiator can be corrected or isolated.

This surveillance is performed by tripping the diesel generator output breaker with the diesel generator carrying the required load while paralleled to offsite power.

TIh 18 menth f*gu*. n.y is based an engineering judgment, taking into conside--;ratioon unit conad-itiefnls rcgquirced to per-fcrm: the sur~veillanee, and is intended to be eatisistent with cpcc fuel eyele letngths. Opcrating cxpriene has shown that thes* components uliual pa, th Sur=eillnaeG when performed t the 18 Mon t-,.ehl frequencY. Therefore, the, fequenc Y i.. acceptabl f.........reliabil standpoint.

This surveillance is modified by a Note to ensure that the diesel generator is tested under load conditions that are as close to design basis conditions as practical. When synchronized with offsite power, testing should be performed at a power factor of*< 0.83 lagging. This power factor is representative of the inductive loading a diesel generator would see under design basis accident conditions. Under certain conditions, however, the note allows the surveillance to be conducted at a power factor other than _< 0.83. These conditions occur when grid voltage is high, and the additional field excitation needed to get the power factor to _< 0.83 results in voltages on the emergency buses that are too high. Under these conditions, the power factor should be maintained as close as practicable to 0.83 while still maintaining acceptable voltage limits on the emergency buses. In other circumstances, the grid voltage may be such that the diesel generator excitation levels needed to obtain a power factor of 0.83 may not cause unacceptable voltages on the emergency buses, but the excitation levels are in excess of those recommended for the diesel MILLSTONE - UNIT 2 B 3/4 8-10 Amendment No. 2-7-7, .-

LDDCR 07-NIP2-009 Mar.I h 29, 2007 3/4.8 ELECTRICAL POWER SYSTEMS BASES generator. In such cases, the power factor shall be maintained as close as practicable to 0.83 lagging without exceeding the diesel generator excitation limits.

SR 4.8.1.1.2.c.5 In the event of a design basis accident coincident with a loss of offsite power, the diesel generators are required to supply the necessary power to ESF systems so that the fuel, RCS, and containment design limits are not exceeded. This surveillance demonstrates the diesel generator operation during a loss of offsite power actuation test signal in conjunction with an ESF actuation signal, including shedding of the nonessential loads and energization of the emergency buses and respective loads from the diesel generator. It further demonstrates the capability of the diesel generator to automatically achieve the required voltage and speed (frequency) within the specified time. The diesel generator auto-start time of 15 seconds is derived from requirements of the accident analysis to respond to a design basis large break LOCA. The surveillance should be continued for a minimum of 5 minutes in order to demonstrate that all starting transients have decayed and stability has been achieved. The requirement to verify the connection of permanent and auto-connected loads is intended to satisfactorily show the relationship of these loads to the diesel generator loading logic. In certain circumstances, many of these loads cannot actually be connected or loaded without undue hardship or potential for undesired operation. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the diesel generator system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

The 18 monetth frcguceney is based en ngnrig judgmient, taking into coensider-ation unit eenditions reqttired to perform the sttryeillanee, and is intended to be eolsistent with exeee fael cycle len1gths. O~pcrtin has shown that these eempenents usually pags the

-xcienee suff eillanee whetn perfcrmcd.._ Mt t.h. 18 menth frequeney. Therefer-e, the frcgucncly is aeeeptabl

'inna ezliability " "a1Idpuin2.

For the purpose of this testing, the diesel generators must be started from a standby condition. Standby condition for a diesel generator means the diesel engine coolant and oil are being circulated and temperature is being maintained consistent with manufacturer recommendations.

This surveillance is modified by a Note. The reason for the Note is that performing the surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. This restriction from normally performing the surveillance in MODE 1 2, 3, or 4 is further amplified to allow portions of the surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g. post work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and MILLSTONE - UNIT 2 B 3/4 8-11 Amendment No. 2-7-7, ,4

.LfBDR /7-mP2-o-9 March 29, 2007 3/4.8 ELECTRICAL POWER SYSTEMS BASES other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is maintained or enhanced. This assessment shall, as a minimum, consider the potential outcomes and transients associated with a failed partial surveillance, a successful partial surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the partial surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and start up to determine that plant safety is maintained or enhanced when portions of the surveillance are performed in MODE 1, 2, 3, or 4. Risk insights or deterministic methods may be used for the assessment.

SR 4.8.1.1.2.c.6 This surveillance demonstrates that diesel generator noncritical protective functions (e.g.,

high jacket water temperature) are bypassed on a loss of voltage signal concurrent with an ESF actuation test signal. During this time, the critical protective functions (engine overspeed, generator differential current, low lube oil pressure [2 out of 3 logic], and voltage restraint overcurrent) remain available to trip the diesel generator and/or output breaker to avert substantial damage to the diesel generator unit. An EDG Emergency Start Signal (Loss of Power signal or SIAS) bypasses the EDG mechanical trips in the EDG control circuit, except engine overspeed, and switches the low lube oil trip to a 2 of 3 coincidence. The loss of power to the emergency bus, based on supply breaker position (A302, A304, and A505 for Bus 24C; A410, A41 1, and A505 for Bus 24D), bypasses the EDG electrical trips in the breaker control circuit except generator differential current and voltage restraint over current. The noncritical trips are bypassed during design basis accidents and provide an alarm on an abnormal engine condition. This alarm provides the operator with sufficient time to react appropriately. The diesel generator availability to mitigate the design basis accident is more critical than protecting the engine against minor problems that are not immediately detrimental to emergency operation of the diesel generator.

l~~~~~~~~~~~

ltulLyi uac* Hcgi~-igmeunlt,:-

_ Jud* taking*

--- iinto consideration uiii The 18 niondh fi egui11y is basd an ~Iilin u~~t aii it urditu m czonditionsr required to perform the surveillanee, and is intended to be eonsistetit with epee fucel eyele lengths. 9pcrtn cxciene hats shown that these eomponents usutilly ptass thc surveillanee when ;.frcda he 18 month fregueney. Therefore, the frequefncy is accceptabl This surveillance is modified by a Note. The reason for the Note is that performing the surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. This restriction from normally performing the surveillance in MODE 1, 2, 3, or 4 is further amplified to allow portions of the surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g. post work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is MILLSTONE - UNIT 2 B 3/4 8-12 Amendment No. 2-_., ,1/

LBDCR ,,-MP2-009 Marceh 29, 2007 3/4.8 ELECTRICAL POWER SYSTEMS BASES maintained or enhanced. This assessment shall, as a minimum, consider the potential outcomes and transients associated with a failed partial surveillance, a successful partial surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the partial surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and startup to determine that plant safety is maintained or enhanced when portions of the surveillance are performed in MODE 1, 2, 3, or 4. Risk insights or deterministic methods may be used for the assessment.

SR 4.8.1.1.2.c.7 This surveillance demonstrates the as designed operation of the standby power sources during loss of the offsite source. This test verifies all actions encountered from the loss of offsite power, including shedding of the nonessential loads and energization of the emergency buses and respective loads from the diesel generator. It further demonstrates the capability of the diesel generator to automatically achieve the required voltage and speed (frequency) within the specified time. The diesel generator auto-start time of 15 seconds is derived from requirements of the accident analysis to respond to a design basis large break LOCA. The surveillance should be continued for a minimum of 5 minutes in order to demonstrate that all starting transients have decayed and stability has been achieved. The requirement to verify the connection and power supply of permanent and auto-connected loads is intended to satisfactorily show the relationship of these loads to the diesel generator loading logic. In certain circumstances, many of these loads cannot actually be connected or loaded without undue hardship or potential for undesired operation. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the diesel generator system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

The 18 menth freqtteney is based ont cgnring dgment, taking into consider-atien uit conditions requir-ed to per-ferm the surn,'illanee, and is intended to be eensistent with expected fuclcycc Ocraing lngth. xpcicnc ha shwn hat thesc eomponents utsually pass thoe surveillancce when per-farmne at the 18 month ffegueney. Ther-efcrce, the frcgucncy is acceptable fro'l a reliability standpotll 1 ;lt. ýinsenrt2a This surveillance is modified by two Notes. The reason for Note 1 is that performing the surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. This restriction from normally performing the surveillance in MODE 1, 2, 3, or 4 is further amplified to allow portions of the surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g. post work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is MILLSTONE - UNIT 2 B 3/4 8-13 Amendment No. 2-7-7, [

LBDCR 07-MP2-009 Marc-h 29, 2007 3/4.8 ELECTRICAL POWER SYSTEMS BASES maintained or enhanced. This assessment shall, as a minimum, consider the potential outcomes and transients associated with a failed partial surveillance, a successful partial surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the partial surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and start up to determine that plant safety is maintained or enhanced when portions of the surveillance are performed in MODE 1, 2, 3, or 4. Risk insights or deterministic methods may be used for the assessment.

Surveillance Note 2 specifies that the start of the diesel generator from a standby condition is not required if this surveillance is performed in conjunction with SR 4.8.1.1.2.c.5.

Since this test is normally performed in conjunction with SR 4.8.1.1.2.c.5, the proposed note will exclude the requirement to start from a standby condition to minimize the time to perform this test. This will reduce shutdown risk since plant restoration, and subsequent equipment availability will occur sooner. In addition, it is not necessary to test the ability of the EDG to auto start from a standby condition for this test since that ability will have already been verified by SR 4.8.1.1.2.c.5, which will have just been performed if the note's exclusion is to be utilized. If this test is to be performed by itself, the EDG is required to start from a standby condition.

SR 4.8. 1.1.2.c.8 This surveillance demonstrates that the diesel generator automatically starts and achieves the required voltage and speed (frequency) within the specified time (15 seconds) from the design basis actuation signal (Safety Injection Actuation Signal) and operates for _ 5 minutes. The 5 minute period provides sufficient time to demonstrate stability. Since the specified actuation signal (ESF signal without loss of offsite power) will not cause the emergency bus loads to be shed, and will not cause the diesel generator to load, the surveillance ensures that permanently connected loads and autoconnected loads remain energized from the offsite electrical power system (Unit 2 RSST or NSST, or Unit 3 RSST or NSST). In certain circumstances, many of these loads cannot actually be connected without undue hardship or potential for undesired operation. It is not necessary to verify all autoconnected loads remain connected. A representative sample is acceptable.

The 18 month frecgucnty is based or ngicrn judgmzent, taking into eensider-ation uit Conditions eq~Auized to pefi tl1 e surveillance, and is intended to be eeniistent with expeeted fite eyele lengths. (4pcrtn cxciene has shown that these eempenents usually pass the

.*-L

__ ,,L .. ... ...- Insert*_ 2a--- . ."--..*. . n.. -.. e*. '. . ";. .*u i surfveillanee when pcfcmc a h- 18 mcneth frequency. Therefore, the frequency is acceptable frma redibdt 'taiidpt.

MILLSTONE - UNIT 2 B 3/4 8-14 Amendment No. 2-7-7, Al

TLBDTR 14 N4P2 009 Maty-8,2014 3/4.8 ELECTRICAL POWER SYSTEMS BASES For the purpose of this testing, the diesel generators must be started from a standby condition. Standby condition for a diesel generator means the diesel engine coolant and oil are being circulated and temperature is being maintained consistent with manufacturer recommendations.

SR 4.8.1.1.2.c.9 This surveillance demonstrates that the diesel engine can restart from a hot condition, such as subsequent to shutdown from a normal surveillance, and achieve the required voltage and speed within 15 seconds. The 15 second time is derived from the requirements of the accident analysis to respond to a design basis large break LOCA.

The 18 m.nth frqun.y is based onfg judgment, taking into c"nsider-ati-n uni conditions required to per-ferm the surveillance,-and iss intentdeed to be consistent with expected fuiel cycle lengths. Opertn exerine has shewn that these compenents usually pass the sufveillance when per-ftrqmepd atthke 18 menth fr-equency. Therefore, the fr-qec iAacc eptabl-e from a reliability standpoint-.

This surveillance is modified by a Note. The Note ensures that the test is performed with the diesel sufficiently hot. The load band is provided to avoid routine overloading of the diesel generator. Routine overloads may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain diesel generator OPERABILITY. The requirement that the diesel has operated for at least 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months at rated load conditions prior to performance of this surveillance is based on manufacturer recommendations for achieving hot conditions. Momentary transients due to changing bus loads do not invalidate this test.

SRs 4.8.1.].2.d. I and 4.8.1.1.2.d.2 the frequency specified in the Surveillance SFrequency Control Program SR 4.8.1.1.2.d. l verifies that, at a 181 day f'equency, the diesel generator starts from standby conditions and achieves required voltage and speed (frequency) within 15 seconds. The 15 second start requirement supports the assumptions of the design basis LOCA analysis in the FSAR. Diesel generator voltage and speed will continue to increase to rated values, and then should stabilize. SR 4.8.1.1.2.d.2 verifies the ability of the diesel generator to achieve steady state voltage and frequency conditions. The time for voltage and speed (frequency) to stabilize is periodically monitored and the trend evaluated to identify degradation of governor or voltage regulator performance when besting in accordance with the requirements of this surveillance.

The 181 day fr-equency for-this surn'eillanee is a r-eduction in cold testing conisistent wit Generic Letter- 84 15. This fr-equency proevidcs adequate assur-ance of diesel gener-ator-OPE*,ABILITY, while minimizingdegradatin resulting fro tefsftg In addition, SR 4.8.1.1.2.d may be performed in lieu of 4.8.1.1.2.a.

MILLSTONE - UNIT 2 B 3/4 8-15 Insert 2b Amendment No. 27-7,

LBDCR 07-MP2-009 Nficlh 29, 2007 3/4.8 ELECTRICAL POWER SYSTEMS BASES For the purpose of this testing, the diesel generators must be started from a standby condition. Standby condition for a diesel generator means the diesel engine coolant and oil are being circulated and temperature is being maintained consistent with manufacturer recommendations.

During performance of SR 4.8.1.1.2.d. 1, the diesel generators shall be started by using one of the following signals:

1. Manual;

2. Simulated loss of offsite power in conjunction with a safety injection actuation signal;

3. Simulated safety injection actuation signal alone; or

4. Simulated loss of power alone.

SR 4.8.1.1.2.d.3 This surveillance verifies that the diesel generators are capable of synchronizing with the offsite electrical system and accepting loads greater than or equal to the equivalent of the maximum expected accident loads. A minimum run time of 60 minutes is required to stabilize engine temperatures, while minimizing the time that the diesel generator is connected to the offsite source. Although no power factor requirements are established by this surveillance, the diesel generator is normally operated at a power factor between 0.8 lagging and 1.0. The 0.8 value is the design rating of the machine, while 1.0 is an operational limitation.

1 184 day fi The ueltu*y fui tlhi SU, veillanc. is a itdut.Un inLuld tstinig conLsisLeIIt With Generic Letter 84- 15 This f4requncy proevides adequate a.u...r.. oif-diesel gnf....

OPERABILITY-, while minimizing degradation resulting frcm testing.

This SR is modified by four Notes. Note 1 indicates that diesel engine runs for this surveillance may include gradual loading, as recommended by the manufacturer, so that mechanical stress and wear on the diesel engine are minimized. Note 2 states that momentary transients because of changing bus loads do not invalidate this test. Similarly, momentary power factor transients above the limit will not invalidate the test. Note 3 indicates that this surveillance should be conducted on only one diesel generator at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations. Note 4 stipulates a prerequisite requirement for performance of this surveillance. A successful diesel generator start must precede this test to credit satisfactory performance.

MILLSTONE - UNIT 2 B 3/4 8-16 Amendment No. "-88,4-92, 234,248, 4, 264-, 2-7, 2-79, 2-93,

hBf)eR 06-MP2-0ý9 july 27, 2006-REFUELING OPERATIONS BASES (Continued) 3/4.9.16 SHIELDED CASK The limitations of this specification ensure that in the event of a shielded cask drop ,1 accident the doses from ruptured fuel assemblies will be within the assumptions of the safety analyses.

3/4.9.17 SPENT FUEL POOL BORON CONCENTRATION The limitations of this specification ensures that sufficient boron is present to maintain spent fuel pool Keff < 0.95 under accident conditions.

Postulated accident conditions which could cause an increase in spent fuel pool reactivity are: a single dropped or mis-loaded fuel assembly, a single dropped or mis-loaded Consolidated Fuel Storage Box, or a shielded cask drop onto the storage racks. A spent fuel pool soluble boron concentration of 1400 ppm is sufficient to ensure Keff < 0.95 under these postulated accident conditions. The required spent fuel pool soluble boron concentration of > 1720 ppm conservatively bounds the required 1400 ppm. The ACTION statement ensure that if the soluble boron concentration falls below the required amount, that fuel movement or shielded cask movement is stopped, until the boron concentration is restored to within limits.

An additional basis of this LCO is to establish 1720 ppm as the minimum spent fuel pool soluble boron concentration which is sufficient to ensure that the design basis value of 600 ppm soluble boron is not reached due to a postulated spent fuel pool boron dilution event. As part of the spent fuel pool criticality design, a spent fuel soluble boron concentration of 600 ppm is sufficient to ensure Keff < 0.95, provided all fuel is stored consistent with LCO requirements. By maintaining the spent fuel pool soluble boron concentration > 1720 ppm, sufficient time is provided to allow the operators to detect a boron dilution event, and terminate the event, prior to the spent fuel pool being diluted below 600 ppm. In the unlikely event that the spent fuel pool soluble boron concentration is decreased to 0 ppm, Keff will be maintained <1.00, provided all fuel is stored consistent with LCO requirements. The ACTION statement ensures that if the soluble boron concentration falls below the required amount, that immediate action is taken to restore the soluble boron concentration to within limits, and that fuel movement or shielded cask movement is stopped. Fuel movement and shielded cask movement is stopped to prevent the possibility of creating an accident condition at the same time that the minimum soluble boron is below limits for a potential boron dilution event. /-periodic The surveillance of the spent fuel pool boron concentration within 24 ho s of fuel movement, consolidated fuel movement, or cask movement over the cask layotrea, verifies that the boron concentration is within limits just prior to the movement. The 7-4ay* surveillance MILLSTONE- UNI,. B 3/4 9-3b Amendment No. 3,0, 4-09, 4-P-7, 4-53, 4-5-5, --7-, 2-0B N24-C

, , -74,2-84, Acknowledged 13y NRC jualy 5, 2007 lis controlled under the Surveillance Frequency Control Program I

v t e Letter Sequence Request
TAC:MF5096, Relocate Surveillance Frequencies to Licensee Control - RITSTF Initiative 5B (Approved, Closed)
Initiation Request, Request Acceptance Administration Questions 6 May 2015 26 June 2015 Answers 5 June 2015 Results Approval Other:
MONTHYEAR2015-05-06 [Table View]

ML14301A112

Text

1.0 DESCRIPTION

3.0 REGULATORY ANALYSIS

4.0 ENVIRONMENTAL CONSIDERATION

5.0 REFERENCES

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