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#REDIRECT [[L-2014-033, Turkey Point ,Units 3 and 4 - License Amendment Request LAR-229, Application for Technical Specification Change Regarding Risk-Informed Justifications for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controll]]
| number = ML14105A042
| issue date = 04/09/2014
| title = Turkey Point ,Units 3 and 4 - License Amendment Request LAR-229, Application for Technical Specification Change Regarding Risk-Informed Justifications for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controll
| author name = Kiley M
| author affiliation = Florida Power & Light Co
| addressee name =
| addressee affiliation = NRC/Document Control Desk, NRC/NRR
| docket = 05000250, 05000251
| license number = DPR-031, DPR-041
| contact person =
| case reference number = L-2014-033, LAR-229
| document type = Letter, License-Application for Facility Operating License (Amend/Renewal) DKT 50, Technical Specification, Amendment
| page count = 216
}}
 
=Text=
{{#Wiki_filter:FPL. April 9, 2014L-2014-033 10 CFR 50.90U. S. Nuclear Regulatory Commission Attn: Document Control DeskWashington, D.C. 20555-0001 Re: Turkey Point Nuclear Plant, Units 3 and 4Docket Nos. 50-250 and 50-251Renewed Facility Operating Licenses DRR-31 and DPR-41License Amendment Request No. LAR-229Application for Technical Specification Change Regarding Risk-Informed Justifications for the Relocation of Specific Surveillance Frequency Requirements to a LicenseeControlled ProgramPursuant to 10 CFR Part 50.90, Florida Power and Light Company (FPL) is submitting a requestfor an amendment to the Renewed Facility Operating Licenses DPR-31 and DPR-41 for TurkeyPoint Nuclear Plant (Turkey Point) Units 3 and 4, respectively.
The proposed amendment would modify the Turkey Point Technical Specifications (TS) by relocating specific surveillance frequencies to a licensee-controlled program with implementation of Nuclear Energy Institute (NEI) 04-10, "Risk-Informed Technical Specification Initiative 5b, Risk Informed Method forControl of Surveillance Frequencies,"
(ADAMS Accession No. ML071360456).
The changes are consistent with NRC-approved Technical Specifications Task Force (TSTF)Standard Technical Specifications (STS) change TSTF-425, "Relocate Surveillance Frequencies to Licensee Control -Risk Informed Technical Specifications Task Force (RITSTF)Initiative 5b," Revision 3, (ADAMS Accession No. ML090850642).
Federal Register "Notice ofAvailability of Technical Specification Improvement to Relocate Surveillance Frequencies toLicensee Control -Risk Informed Specification Task Force (RITSTF)
Initiative 5b, Technical Specification Task Force -425, Revision 3," published on July 6, 2009 (74 FR 31996)announced the availability of this TS improvement.
Attachment 1 provides a description of the proposed
: changes, the requested confirmation ofapplicability, and plant-specific verifications.
Attachment 2 provides documentation ofprobabilistic risk assessment (PRA) technical adequacy.
Attachment 3 provides the existing TSpages marked-up to show the proposed
: changes, and Attachment 4 provides the proposed TSBases changes.
The changes to the TS Bases are provided for information only and will beincorporated in accordance with the TS Bases Control Program upon implementation of theapproved amendment.
Attachment 5 contains the Proposed No Significant HazardsConsideration Determination.
Attachment 6 provides a cross-reference between thesurveillance requirements (SR) contained in TSTF-425 and the SR in the Turkey Point TS.Florida Power & Light Company9760 S.W. 344' Street Homestead, FL 33035 Turkey Point Units 3 and 4 L-2014-033 Docket Nos. 50-250 and 50-251 Page 2 of 2Please process these changes within one (1) year of receipt, and once approved, theamendments will be implemented within 90 days. This letter contains no new commitments andno revisions to existing commitments.
These changes have been reviewed by the Turkey Point Plant Nuclear Safety Committee.
Pursuant to 10 CFR 50.91 (b)(1), a copy of this submittal is being forwarded to the designated State of Florida official.
Should you have any questions regarding this submittal, please contact Mr. Robert J. Tomonto,Licensing
: Manager, at (305) 246-7327.
I declare under penalty of perjury that the foregoing is true and correct.Executed on the ninth day of April 2014.Very truly yours,Michael KileySite Vice President Turkey Point Nuclear PlantAttachments (6)cc: USNRC Regional Administrator, Region IIUSNRC Project Manager, Turkey Point Nuclear PlantUSNRC Senior Resident Inspector, Turkey Point Nuclear PlantMs Cindy Becker, Florida Department of Health Turkey Point Units 3 and 4Docket Nos. 50-250 and 50-251L-2014-033 Attachment 1Attachment 1Turkey Point Nuclear PlantDescription and Assessment License Amendment Request No. LAR-229
 
==Subject:==
 
Application for Technical Specification Change Request Regarding Risk-Informed Justifications for the Relocation of Specific Surveillance Frequency Requirements toa Licensee Controlled Program1.0 DESCRIPTION
 
==2.0 ASSESSMENT==
2.1 Applicability of Published Safety Evaluation 2.2 Optional Changes and Variations 3.0 REGULATORY ANALYSIS3.1 No Significant Hazards Consideration 3.2 Applicable Regulatory Requirements
/ Criteria3.3 Conclusion 4.0 ENVIRONMENTAL CONSIDERATION
 
==5.0 REFERENCES==
 
Page 1 of 6 Turkey Point Units 3 and 4 L-2014-033 Docket Nos. 50-250 and 50-251 Attachment 11.0 DESCRIPTION The proposed amendment would modify the Turkey Point Nuclear Plant (Turkey Point),Units 3 and 4 Technical Specifications (TS) by relocating specific surveillance frequencies to a licensee-controlled program with the adoption of Technical Specification Task Force (TSFT)-425, Revision 3, "Relocate Surveillance Frequencies to LicenseeControl -Risk Informed Technical Specification Task Force (RITSTF)
Initiative 5b"[Reference 1]. Additionally, the change would add a new program, the Surveillance Frequency Control Program (SFCP) to TS Section 6.0, Administrative
: Controls, Subsection 6.8, Procedures and Programs.
The changes are consistent with NRCapproved industry
/ TSTF Standard Technical Specifications (STS) change TSTF-425, Revision
: 3. Federal Register "Notice of Availability of Technical Specification Improvement to Relocate Surveillance Frequencies to Licensee Control -Risk InformedSpecification Task Force (RITSTF)
Initiative 5b, Technical Specification Task Force -425, Revision 3," published on July 6, 2009 (74 FR 31996) [Reference 2] announced theavailability of this TS improvement.
 
==2.0 ASSESSMENT==
2.1 Applicability of Published Safety Evaluation Florida Power and Light Company (FPL) has reviewed the safety evaluation datedJuly 6, 2009. The review included a review of the NRC staff's evaluation, TSTF-425, Revision 3, and the requirements specified in Nuclear Energy Institute (NEI) 04-10,Revision 1 "Risk-Informed Method for Control of Surveillance Frequencies,"
[Reference 3].Attachment 2 includes FPL's documentation with regard to PRA technical adequacyconsistent with the requirements of Regulatory Guide (RG) 1.200, Revision 1, "AnApproach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results in Risk-Informed Activities,"
[Reference 4], Section 4.2, and describes anyProbabilistic Risk Assessment (PRA) models without NRC-endorsed standards, including documentation of the quality characteristics of those models in accordance with RG 1.200.FPL has concluded that the justifications presented in the TSTF proposal and the safetyevaluation prepared by the NRC staff are applicable to Turkey Point Units 3 and 4 andjustify this amendment to incorporate the changes to the Turkey Point TS.2.2 Optional Changes and Variations The proposed amendment is consistent with STS changes described in TSTF-425, Revision 3, but FPL proposes variations or deviations from TSTF-425, as described below:1. Revised (clean) TS pages are not included in this amendment request given thenumber of TS pages affected, the straightforward nature of the proposed changes,and outstanding license amendment requests that may affect some of the same TSpages. Providing only mark-ups of the proposed TS changes satisfies therequirements of 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit,"
in that the mark-ups fully describe the changes desired.Page 2 of 6 Turkey Point Units 3 and 4 L-2014-033 Docket Nos. 50-250 and 50-251 Attachment 1This is an administrative deviation from the NRC staffs model application datedJuly 6, 2009 (74 FR 31996) with no impact on the NRC staffs model safetyevaluation published in the same Federal Register Notice. As a result of thisdeviation, the contents and numbering of the attachments for this amendment request differ from the attachments specified in the NRC staff's model application.
: 2. The Turkey Point TS were based on the standard TS at the time they were issued.As a result, the Turkey Point TS surveillance numbers and associated Basesnumbers differ from the surveillance numbers and Bases numbers in NUREG-1431, "Standard Technical Specifications
-Westinghouse Plants,"
Revision 4, Volumes 1and 2 [Reference 5] and TSTF-425, Revision
: 3. In addition, the Administrative Controls Section TS is Section 6.0 for Turkey Point verses Section 5.0 forNUREG-1431.
These differences are administrative deviations from TSTF-425 withno impact on the NRC staffs model safety evaluation dated July 6, 2009(74 FR 31996).There are surveillances contained in NUREG-1431 that are not contained in theTurkey Point TS. These surveillances identified in TSTF-425 for NUREG-1431 arenot applicable to Turkey Point. This is an administrative deviation from TSTF-425with no impact on the NRC staffs model safety evaluation dated July 6, 2009(74 FR 31996).3. The Turkey Point TS include plant-specific surveillances that are not contained inNUREG-1431 and, therefore are not included in the NUREG-1431 surveillances provided in TSTF-425.
FPL has determined that the relocation of the frequencies forthese Turkey Point specific surveillances is consistent with TSTF-425, Revision 3,and with the NRC staffs model safety evaluation dated July 6, 2009 (74 FR 31996),including the scope exclusions identified in Section 1.0, "Introduction,"
of the modelsafety evaluation, because the plant-specific surveillance frequencies involve fixedperiod frequencies.
Changes to the frequencies for these plant-specific surveillances would be controlled under the SFCP.The SFCP provides the necessary administrative controls to require thatsurveillances related to testing, calibration, and inspection are conducted at afrequency to assurethat the necessary quality of the systems and components ismaintained, the facility operation will be within safety limits, and that the LimitingConditions for Operation will be met. Changes to frequencies in the SFCP would beevaluated using the methodology and probabilistic risk guidelines contained inNEI 04-10, Revision 1, "Risk-Informed Technical Specifications Initiative 5b,Risk-Informed Method of Control of Surveillance Frequencies,"
as approved by NRCletter "Final Safety Evaluation for Nuclear Energy Institute (NEI) Topical Report (TR)04-10, Revision 1, "Risk Informed Technical Specification Initiative 5b, "Risk-Informed Method for Control of Surveillance Frequencies(TAC No. MD61 11)," datedSeptember 19, 2007 [Reference 6].The NEI 04-10, Revision 1 methodology includes qualitative considerations, riskanalyses, sensitivity studies and bounding
: analyses, as necessary, andrecommended monitoring of the performance of systems, structures, andcomponents (SSCs) for which frequencies are changed to assure that reducedtesting does not adversely impact the SSCs. The NEI 04-10 Revision 1 methodology Page 3 of 6 Turkey Point Units 3 and 4 L-2014-033 Docket Nos. 50-250 and 50-251 Attachment 1satisfies the five key safety principles specified in RG 1.177, "An Approach forPlant-Specific Risk-Informed Decision Making: Technical Specifications,"
datedAugust 1998 [Reference 7], relative to changes in surveillance frequencies.
Therefore, the proposed relocation of the Turkey Point-specific surveillance frequencies is consistent with TSTF-425 and with the NRC staff's model safetyevaluation dated July 6, 2009 (74 FR 31996).4. The definition of STAGGERED TEST BASIS is being retained in the Turkey Point TSDefinition Section 1.0 since the terminology is being maintained in TS Surveillance Requirements in Sections 3/4.3, Instrumentation, 3/4.7, Plant Systems, and 3/4.8,Electrical Power Systems.
In addition, the terminology is used in Section 6.8.4.k,"Control Room Envelop Habitability Program,"
which is not the subject of thisamendment request and is not proposed to be changed.
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).5. The insert provided in TSTF-425 for the TS Bases (Insert 2) states "The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk andis controlled under the Surveillance Frequency Control Program."
In a letter datedApril 14, 2010 [Reference 8], the NRC staff agreed that the insert applies tosurveillance frequencies that are relocated and subsequently evaluated and changedin accordance with the SFCP, but does not apply to frequencies relocated to theSFCP, but not changed.
Therefore, the insert for the Bases is revised to "TheSurveillance Frequency is controlled under the Surveillance Frequency ControlProgram."
This is an administrative deviation from TSTF-425 with no impact on theNRC staffs model safety evaluation dated July 6, 2009 (74 FR 31996).6. The Turkey Point TS were based on the standard TS at the time they were issuedwhich did not contain Bases as comprehensive as those in NUREG-1431.
Therefore, many of the Bases mark-ups in TSTF-425 are not applicable to theTurkey Point TS. The proposed Bases changes in Attachment 4 revise only thoseBases that currently discuss surveillance frequencies.
This is an administrative deviation from TSTF-425 with no impact on the NRC staff's model safety evaluation dated July 6, 2009 (74 FR 31996). The existing Bases information describing thebasis for the surveillance frequencies will be relocated to the Turkey Point SFCP.7. The SR for the Reactor Trip System Instrumentation and Engineered SafetyFeatures Actuation System Instrumentation in Turkey Point TS 3.3.1 and 3.3.2 arepresented in tabular format, which is different from the format of the SR for the sameinstrumentation in NUREG-1431.
To accommodate this difference, the proposedchanges includes use of "SFCP" as a frequency notation in the tables that specifyinstrumentation SR. This is an administrative deviation from TSTF-425 due todifferences in format between Turkey Point TS and NUREG-1431, which has noimpact on the NRC staffs model safety evaluation dated July 6, 2009 (74 FR 31996).8. TS Table 3.3-4, Action Statements, Action 27 is being revised to change "expect" to"except" and TS 3.7.1.2 is being revised to change "APPLICA81LITY" to"APPLICABILITY".
These differences from TSTF-425 are editorial changes tocorrect existing typographical errors and have no impact on the NRC staffs modelsafety evaluation dated July 6, 2009 (74 FR 31996).Page 4 of 6 Turkey Point Units 3 and 4 L-2014-033 Docket Nos. 50-250 and 50-251 Attachment 13.0 REGULATORY ANALYSIS3.1 No Significant Hazards Consideration FPL has reviewed the proposed no significant hazards consideration (NSHC)determination published in the Federal Register July 6, 2009 (74 FR 31996). FPL hasconcluded that the proposed NSHC presented in the Federal Register notice isapplicable to Turkey Point and is provided as Attachment 5 to this amendment requestwhich satisfies the requirements of 10 CFR 50.91(a).
3.2 Applicable Regulatory Requirements
/ CriteriaA description of the proposed changes and their relationship to applicable regulatory requirement is provided in TSTF-425, Revision 3 (ADAMS Accession No.ML090850642) and the NRC staffs model safety evaluation published in the FederalRegister is applicable to Turkey Point.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 inthe proposed manner, (2) such activities will be conducted in compliance with theCommission's regulations, and (3) the issuance of an amendment will not be inimical tothe common defense and security or to the health and safety of the public.4.0 ENVIRONMENTAL CONSIDERATION FPL reviewed the environmental consideration included in the NRC staffs model safety.evaluation published in the Federal Register on July 6, 2009 (74 FR 31996). FPLconcluded that the NRC staff's findings presented therein are applicable to Turkey Pointand the determination is hereby incorporated by reference to this application.
The proposed change does not involve (i) a significant hazards consideration, (ii) asignificant change in the types or significant increase in the amounts of any effluent thatmay be released
: offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure.
Accordingly, the proposed change meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9).
Therefore, pursuant to10 CFR 51.22(b),
no environmental impact statement or environmental assessment need be prepared in connection with the proposed change.
 
==5.0 REFERENCES==
: 1. Technical Specification Task Force (TSTF)-425, Revision 3, "Relocate Surveillance Frequencies to Licensee Control -RITSTF Initiative 5b," March 18, 2009 (ADAMSAccession No. ML090850642).
Page 5 of 6 Turkey Point Units 3 and 4 L-2014-033 Docket Nos. 50-250 and 50-251 Attachment
: 12. 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 (TSTF)-425, Revision 3,July 6, 2009 (74 FR 31966).3. Nuclear Energy Institute (NEI) 04-10, Revision 1, "Risk-Informed Method for Control ofSurveillance Frequencies,"
April 2007 (ADAMS Accession No. ML071360456).
: 4. Regulatory Guide (RG) 1.200, Revision 1, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results in Risk-Informed Activities,"
Revision 1, January 2007 (ADAMS Accession No. ML070240001).
: 5. NUREG-1431, "Standard Technical Specifications
-Westinghouse Plants,"
Revision 4,Volumes 1 and 2, April 30, 2012, (ADAMS Accession Nos. ML12100A222 andML12100A228).
: 6. H. K. Niedh (NRC) letter to B. Bradley (NE), "Final Safety Evaluation for Nuclear EnergyInstitute (NEI) Topical Report (TR) 04-10, Revision 1, "Risk-Informed Technical Specification Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies" (TAC No. MD6111),
September 19, 2007, (ADAMS Accession No.ML072570267)
: 7. Regulatory Guide (RG) 1.177, "An Approach for Plant-Specific, Risk Informed Decision-Making: Technical Specifications,"
August 1998 (ADAMS Accession No. ML003740176).
: 8. NRC letter to Technical Specifications Task Force, "Notification of Issue with NRC-Approved Technical Specifications Task Force (TSTF) Traveler TSTF-425, Revision 3,"Relocate Surveillance Frequencies to Licensee Control -RITSTF Imitative 5b,"April 14, 2010 (ADAMS Accession No. ML1 00990099).
Page 6 of 6 Turkey Point Units 3 and 4Docket Nos. 50-250 and 50-251L-2014-033 Attachment 2Attachment 2Turkey Point Nuclear PlantLicense Amendment Request No. LAR-229Documentation of Probabilistic Risk Assessment (PRA)Technical AdequacyThis coversheet plus 65 pages.
Documentation of PRA Technical AdequacyTable of Contents1.0 Introduction
..........................................................................................................
32.0 Background
..........................................................................................................
52.1 RG 1.200 and PRA Standard
..........................................................................
52.2 Turkey Point PRA History .........................................................................
52.3 Model Change Database
.........................................................................
62.4 Turkey Point PRA Capability Target ..........................................................
72.5 Assessment Process ................................................................................
83.0 Evaluation
.........................................................................................................
83.1 Parts 2 and 3 -Internal Events and Internal Flooding
................................
83.2 Parts 4 to 9 -External Events ...................................................................
93.3 PRA Model Maintenance and Control ....................................................
114.0 Conclusion
..........................................................................................................
115.0 References
..........................................................................................................
12Enclosure
-Peer Review Findings
............................................................................
132
 
==1.0 INTRODUCTION==
 
The implementation of the Surveillance Frequency Control Program (SFCP, alsoreferred to as Technical Specifications Initiative 5b) at Turkey Point Station will follow theguidance'provided in NEI 04-10, Revision 1 [Reference 1] in evaluating proposedsurveillance test interval (STI) changes.
The following steps of the risk-informed STIrevision process are common to all proposed STI changes within the proposed licenseecontrolled program." Each proposed STI revision is reviewed to determine whether there are anycommitments made to the NRC that may prohibit changing the interval.
If thereare no related commitments, or the commitments may be changed using acommitment change process based on NRC-endorsed
: guidance, then evaluation of the STI revision can proceed.
If a commitment exists, and the commitment change process does not permit the change without NRC approval, then the STIrevision cannot be implemented.
Only after receiving NRC approval to changethe commitment could a STI revision proceed." A qualitative analysis is performed for each STI revision that involves severalconsiderations as explained in NEI 04-10, Revision 1.* Each STI revision is reviewed by an expert panel, referred to as the Integrated Decision-making Panel (IDP), which is normally the same panel used forMaintenance Rule implementation, but with the addition of specialists withexperience in surveillance tests and system or component reliability.
If the IDPapproves the STI revision, the change is documented, implemented, andavailable for future audits by the NRC. If the IDP does not approve the STIrevision, the STI value is left unchanged.
* Performance monitoring is conducted as recommended by the IDP. In somecases, no additional monitoring may be necessary beyond that alreadyconducted under the Maintenance Rule. Performance monitoring helps toconfirm that no failure mechanisms related to the revised test interval aresubsequently identified as sufficiently significant to alter the basis provided in thejustification for the surveillance interval change." The IDP is responsible for periodic review of performance monitoring results.
If itis determined that the time interval between successive performances of asurveillance test is a factor in the unsatisfactory performances of the surveillance, the IDP returns the STI back to the previously acceptable STI." In addition to the above steps, the Probabilistic Risk Assessment (PRA) is used,when possible, to quantify the effect of a proposed individual STI revisioncompared to acceptance criteria in NEI 04-10, Revision
: 1. Also, the cumulative impact of risk-informed STI revisions on PRA evaluations (i.e., internal events,external events, and shutdown) is compared to the risk acceptance criteria asdelineated in NEI 04-10, Revision
: 1. For those cases where the STI cannot bemodeled in the plant PRA (or where a particular PRA model does not exist for agiven hazard group), a qualitative or bounding analysis is performed to providejustification for the acceptability of the proposed test interval change.The NEI 04-10, Revision 1 methodology endorses the guidance provided in Regulatory Guide (RG) 1.200, Revision 1, "An Approach for Determining the Technical Adequacy ofProbabilistic Risk Assessment Results for Risk-Informed Activities."
The guidance in RG3 1.200 indicates that the following steps should be followed when performing PRAassessments:
: 1. Identify the parts of the PRA used to support the application.
* Identify structures,
: systems, and components (SSCs), and operational characteristics that are affected by the application and how these areimplemented in the PRA model.* A definition of the acceptance criteria used for the application.
: 2. Identify the scope of risk contributors addressed by the PRA model.If not full scope (i.e., internal events, external events, applicable modes),identify appropriate compensatory measures or provide boundingarguments to address the risk contributors not addressed by the PRAmodel.3. Summarize the risk assessment methodology used to assess the risk of theapplication.
* Include how the PRA model was modified to appropriately model the riskimpact of the change request.4. Demonstrate the technical adequacy of the PRA." Identify plant changes (design or operational practices) that have beenincorporated at the site, but are not yet in the PRA model and justify whythe change does not impact the PRA results used to support theapplication.
* Document peer review findings and observations that are applicable tothe parts of the PRA required for the application, and for those that havenot yet been addressed, justify why the significant contributors would notbe impacted.
* Document that the parts of the PRA used in the decision are consistent with applicable standards endorsed by the RG (currently, RG 1.200,Revision 1, which includes only the internal events PRA standard).
Provide justification to show that where specific requirements in thestandard are not adequately met, it will not unduly impact the results.* Identify key assumptions and approximations relevant to the results usedin the decision-making process.Because of the broad scope of potential Initiative 5b applications and the fact that theimpact of such assumptions differs from application to application, each of the issuesencompassed in Items 1 through 3 will be covered with the preparation of eachindividual PRA assessment made in support of the individual STI interval requests.
Thepurpose of the remaining portion of this attachment is to address the requirements identified in item 4 above.This evaluation summarizes the assessment of the Turkey Point PRA capability asmeasured against the current ASME/ANS PRA Standard (ASME/ANS RA-Sa-2009)
[Reference 2], endorsed by NRC Regulatory Guide (RG) 1.200, Revision 2 [Reference 3]. While the NEI guidance document refers to RG 1.200, Revision 1, which includes4 only the internal events PRA standard (ASME RA-Sb-2005),
this evaluation addresses the broader scope of RG 1.200, Revision
: 2. This assessment addresses the technical adequacy of the Turkey Point PRA for use in risk-informed applications.
The assessment is based on a series of formal peer reviews and other technical
: reviews, documented in the peer review reports.
This assessment uses the latestTurkey Point PRA model update [Reference 4] and internal flood analysis
[Reference 5].2.0 BACKGROUND 2.1 RG1.200 and PRA StandardThe ASME/ANS PRA Standard (ASME/ANS RA-Sa-2009) has eight "parts" withtechnical
: elements, high level requirements (HLRs), and detailed supporting requirements (SRs). These parts represent the major classes of hazards included in aPRA:e Part 2, internal events (addressed in Section 3.1),e Part 3, internal flood (addressed in Section 3.1),* Part 4, internal fire (addressed in Section 3.2),e Part 5, seismic events (addressed in Section 3.2),a Parts 6 to 9, other external hazard events (addressed in Section 3.2).Note -Part 1 of the PRA Standard is introductory information and does not contain anyrequirements except configuration control (addressed in Section 3.3).NRC Reg Guide 1.200, Revision 2 endorses this Standard with minor "clarifications."
The Standard supporting requirements allow the assessment of the portions of the PRAas Capability Category CC-I, CC-Il, or CC-Ill, with increasing scope and level of detail,plant-specificity, and realism.
Thus, the overall assessment of PRA capability is thecollection of the assessments of the hundreds of supporting requirements.
2.2 Turkey Point PRA HistoryThe Turkey Point PRA was originally developed in 1991 for the IPE submittal
[Reference 6] as a Level 2 risk assessment of at-power operation of Turkey Point addressing internal events including fires and floods. This PRA was subject to a number of reviews,internal and external, during its preparation as well as extensive review by NRC throughnational labs following its publication.
The first of these reviews consisted of normalengineering quality assurance practices carried out by the organization performing theanalysis.
A qualified individual with knowledge of PRA methods and plant systemsperformed an independent review of the results for each task. This represented adetailed check of the input to the PRA model and provided a high degree of qualityassurance.
The second level of review was performed by plant personnel not directly involved withthe development of the PRA model: This review was performed by individuals fromOperations, Technical Staff, Training, and the Independent Safety Engineering Group,5 who reviewed the system description notebooks and accident sequence description.
This provided diverse expertise with plant design and operations knowledge to reviewthe system descriptions for accuracy.
The third level of review was performed by PRA experts from ERIN Engineering.
Thisreview provided broad insights on techniques and results based on experience fromother plant PRAs. The review team reviewed the PRA development procedures, as wellas the output products.
Comments obtained from all the review sources were incorporated, as appropriate, intothe work packages and the final product.
Following the Turkey Point IPE submittal to theNRC on June 25, 1991, it was reviewed extensively by the NRC and NRC contractors.
In fact, the Turkey Point IPE was one of the few IPE submittals to receive a Step 1 and aStep 2 review by the NRC. The Step 2 review consisted of a team of NRCrepresentatives and contractors visiting FPL to conduct a week-long, extensive review ofthe Turkey Point IPE. Following these reviews, the Turkey Point IPE was revised in early1992, and FPL received the NRC Safety Evaluation Report (SER) for the Turkey PointIPE on October 15, 1992. The SER concluded that the Turkey Point IPE had met theintent of GL 88-20.The Turkey Point Internal Events Peer Review was performed in January 2002 using theNEI 00-02 process.
Following the issuance of the ASME PRA Standard and Regulatory Guide 1.200 (RG 1.200), an internal gap analysis was performed where the findingsfrom the original 2002 peer review were incorporated into the overall assessment of thePRA's quality with respect to the Standard's supporting requirements.
The currentTurkey Point gap analysis uses the RA-Sa-2009 version of the standard as endorsed byRG 1.200, Revision 2.To supplement the original peer review and internal gap analysis, and to further verifythe quality of the updated internal events model used in the Fire PRA, in April 2011, afocused peer review was performed assessing the human reliability analysis (HRA) andinternal flooding analysis portions of the PRA using the latest PRA standard, ASME/ANSRA-Sa-2009, and Regulatory Guide 1.200, Rev. 2. The internal flooding analysisfocused peer review was performed because the latest internal flooding analysis was amuch more comprehensive analysis than the original screening analysis that wasperformed for the IPE [Reference 6]. Although the basic methods used for the HRA hadnot changed substantially, the HRA focused peer, review was performed because of theenhanced HRA dependency analysis and the use of the HRA Calculator software in thelatest model, and the fact that HRA plays a significant role in the determination of thedominant sequences and overall risk profile.Finally, a peer review was performed in October 2013, to assess portions of the PRAmodel which had received upgrades:
: 1) Common-cause failure analysis
-use of alphafactors;
: 2) Level 2 analysis
-upgrade to the latest methodology; and 3) Interfacing system LOCAs -upgrade to the latest methodology.
Significant findings from the peer reviews, along with their resolutions, are listed in theEnclosure.
2.3 Model Chan-qe DatabaseThe living PRA is maintained through use of the plant Change Database.
A samplescreen shot of the input form is shown below.6 PTN PSA Change Lo EAll Records are shownN Umber:Title:Files Affected:
 
==
Description:==
 
Details of ActualChanges:FPTN-O0-O01 Add New Log. .Delete ....This ..Lo.......
* Ilemova.
of."breaker racked out" and "breaker not racked out" flagsThe "breaker racked out" and "breaker not racked out" flags forCC'W and ICv pumps are cumbersome and unnecessary, especially in the use ot EOOS. The "breaker racked out" flag willbe replaced with the relevant maintenance event, and the"breaker not racked out" flag will be replaced with the NOT ofthe relevant maintenance event. With the use of FORTE. NOTgates are now quantifiable.
The tollowing changes were made.Delete C6OOZ1 1Replace Z-C0011 with CTM4OCCCWPA in gReplace 0C0011 with CTM40CCv4-PA in g:ii, C ° ., m n ,, : Jl'. ....... ......................
: .. ...... ..... ..Comments:
ji ...~ ~ .......................APiepared By:: jW ,**.Fitte Date Prepared:
r2/25/2000 Print This?..Status (Open/Closed):*Closed ImplementedY: 21 0*Date Implemented.:
/ 3/2000R-:d4 1 of 641 ' .' Unrfiltered
'Searchate Cl 451 LL.ate C1i 451 K2.r Itemaare:P.... .--- ---- n t----- -This database is used to store the details of all modifications, proposed and actual, openor closed, for the Turkey Point PRA model. This includes findings and observations frompeer reviews, self-assessments, and issues identified during use and update of the PRAmodel. The open items are all model enhancements or documentation issues, and havebeen judged not to significantly impact PRA model applications.
Open items will beaddressed in future PRA updates, based on the significance of the open item and thescope of the update.As part of the PRA evaluation for each STI change request, a review of open modelchanges for Turkey Point will be performed and an assessment of the impact on theresults of the application will be made prior to presenting the results of the risk analysisto the IDP. If a nontrivial impact is expected, then this may include the performance ofadditional sensitivity studies or PRA model changes to confirm the impact on the riskanalysis.
2.4 Turkey Point PRA Capability TarqetThe target capability level for the Turkey Point PRA is Capability Category II (CC-II).That is, the goal is to meet all supporting requirements (SRs) at least at the CC-Il level.This is the maximum capability level needed by any foreseeable application.
Note that in many supporting requirements, the requirement spans all three capability categories.
Thus, if the SR is met, it meets CC Ill. While CC II is the target, CC III is metin many SRs.7 2.5 Assessment ProcessThe assessment of PRA capability judges the Turkey Point PRA against each supporting requirement in the PRA Standard as "Meets" CC-I, CC-Il, or CC-Ill. If the PRA does notmeet the requirements of category CC-Il for a specific SR, it is assessed as "Not Met."This assessment is captured in a Microsoft Access database.
There is a table in thisdatabase with the SR-by-SR assessments from industry peer reviews and internal self-assessments.
There is a separate database with tables with Facts and Observations (F&Os) from the WOG peer review and the focused peer reviews, along with their statusand resolutions.
 
==3.0 EVALUATION==
The following sections describe the capability of the Turkey Point PRA for the majorStandard parts.3.1 Parts 2 and 3 -Internal Events and Internal FloodingThe internal events portion of the Turkey Point PRA has been updated a number oftimes since the original IPE submittal.
As described in Section 2.2, there has been one global peer review, and focused peerreviews in the following areas: HRA, internal
: flooding, CCF, Level 2, and ISLOCA.Three peer reviews have been conducted against internal event supporting requirements:
* In 2002, a review of all technical elements was performed using the industry PRACertification
: process, the precursor to the PRA Standard.
The 2002 peer reviewresulted in 60 findings and observations (2 "A" level, 28 "B" level, 28 "C" level,and 2 "S (Superior) level). All of the findings and observations have beenaddressed in the model updates following this peer review.* In 2011, a focused peer review was performed for the elements IF and HR. Thisassessment replaced the 1999 peer review for those elements that were inscope. This review was done using the current PRA Standard (ASME/ANS RA-Sa-2009).
The 2011 focused peer review resulted in 21 findings, 7 suggestions, and 1 strength.
All of the findings and suggestions have been resolved, and,where changes were necessary, addressed in a model update.* In 2013, a focused peer review was performed to review upgrades to the CCF,Level 2, and ISLOCA analyses.
This review was done using the current PRAStandard (ASME/ANS RA-Sa-2009) and Regulatory Guide 1.200, Rev. 2. Thepeer review resulted in 11 findings and 2 suggestions.
These findings andsuggestions have not yet been resolved in the current PRA model, but will eitherbe addressed via model updates before the implementation of 5b, or shown tohave an insignificant impact on the 5b application.
Conclusion The findings and F&Os that have not yet been resolved will either be resolved in modelupdates before the implementation of the 5b application, or shown not to represent asignificant deficiency in the analyses necessary to support the 5b application.
8 3.2 Parts 4 to 9 -External EventsThe NEI 04-10 methodology allows for STI change evaluations to be performed in theabsence of quantifiable PRA models for all external hazards.
For those cases where theSTI cannot be modeled in the plant PRA (or where a particular PRA model does notexist for a given hazard group), a qualitative or bounding analysis is performed toprovide justification for the acceptability of the proposed test interval change.3.2.1 Part 4 -Internal FireA fire PRA was performed for Turkey Point as part of the 1991 IPE submittal.
Since itwas done for the IPE, it was more of a screening analysis to discover any firevulnerabilities than an attempt to determine a realistic estimate of core damage risk dueto fire. It has not been updated since the original submittal.
Turkey Point is an NFPA-805 plant, and therefore has a fire PRA to support the NFPA-805 effort. The fire PRA uses the latest internal events PRA model as a basis. TheTurkey Point NFPA-805 fire PRA uses NUREG/CR-6850 guidance as required byNFPA-805, and thus produces a conservative estimate of core damage risk due to fire.A peer review of the Turkey Point (PTN) Fire PRA was performed in February 2010 atPTN using the NEI 07-12 Fire PRA peer review process, the combined PRA standard, ASME/ANS RA-Sa-2009, and RG 1.200, Revision
: 2. The purpose of this review was toprovide a method for establishing the technical quality and adequacy of the Fire PRA forthe spectrum of potential risk-informed plant licensing applications for which the FirePRA may be used. The February 2010 PTN Fire PRA Peer Review was a full-scope review of all the Technical Elements of Part 4 of the ASME/ANS standard.
This reportwas issued to PTN in April 2010 [Reference 8]. A subsequent peer review performed inMarch 2012 was a focused scope peer review addressing the FSS, HRA and PRMTechnical Elements.
The report was finalized and issued to PTN in May 2012[Reference 9].The Fire PRA update addressed the Supporting-Requirement-assessed deficiencies (i.e., Not Met or CCI). Completion of recommendations related to Supporting Requirement assessments and 'Finding' F&Os results in a Capability Category IIassessment for the majority of the Supporting Requirements.
Conclusion Based on the completion of peer review recommendations and the assessment ofdeferred items, the Turkey Fire PRA is adequate to support this application, with thecaveat that the PRA is a conservative representation of the fire risk from operation ofTurkey Point Station.
The Fire PRA model will be exercised to obtain quantitative firerisk insights, but refinements may need to be made on a case-by-case basis.3.2.2 Part 5 -Seismic EventsTurkey Point is sited in an area of very low seismicity.
There is no seismic PRA forTurkey Point. For the seismic portion of the Turkey Point IPEEE (Reference 7), FPLused the FPL site-specific seismic program associated with Unresolved Safety Issue9 O1-sseo Isow u! pz!i!lln aq ii!M qoeoJdde6uipunoq e JO aA!leB!Ienb e 'sdnoJ6 pJezeq JaqjLo eqBl 104 suauwssesse eql 6u!uwJOjed u! 'ejojejeiej_
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'zO-,L Jei,9i o!JeUeo) 9k-V (1sn) 3.2.4 Conclusion
-External EventsAs stated earlier, the NEI 04-10 methodology allows for STI change evaluations to beperformed in the absence of quantifiable PRA models for all external hazards.Therefore, in performing the assessments for the other hazard groups, a qualitative or abounding approach will be utilized in most cases. The Fire PRA model will be exercised to obtain quantitative fire risk insights but refinements may need to be made on a case-by-case basis. This approach is consistent with the accepted NEI 04-10 methodology.
3.3 PRA Model Maintenance and ControlPRA model maintenance and control requirements are described in the PRA Standard, Section 1-5. These requirements are addressed in the current set of Nextera/FPL fleetprocedures that address model maintenance and control:EN-AA-105, Probabilistic Risk Assessment ProgramEN-AA-105-1000, PRA Configuration Control and Model Maintenance EN-AA-105-10000, Control of PRA Documentation and Evaluations
 
==4.0 CONCLUSION==
 
The Turkey Point PRA model of record fully meets all the requirements of Part 2(Internal Events) and Part 3 (Internal Flood) of the current ASME/ANS PRA Standard.
All significant findings from peer reviews or other technical reviews have beenaddressed and closed.Based on the completion of peer review recommendations and the assessment ofdeferred items, the Turkey Fire PRA is adequate to support this application, with thecaveat that the PRA is a conservative representation of the fire risk from operation ofTurkey Point Station.
The Fire PRA model will be exercised to obtain quantitative firerisk insights, but refinements may need to be made on a case-by-case basis.Seismic risk at Turkey Point is minimal and will not be a significant factor in the 5bapplication.
As stated earlier, the NEI 04-10 methodology allows for STI change evaluations to beperformed in the absence of quantifiable PRA models for all external hazards.Therefore, in performing the assessments for the other hazard groups, a qualitative or abounding approach will be utilized in most cases. This approach is consistent with theaccepted NEI 04-10 methodology.
11
 
==5.0 REFERENCES==
: 1. NEI 04-10, Risk-Informed Technical Specifications Initiative 5b Risk-Informed Method for Control of Surveillance Frequencies, April 2007.2. ASME/ ANS RA-Sa-2009, "Addenda to ASME/ ANS RA-S-2008 Standard forLevel 1/ Large Early Release Frequency Probabilistic.Risk Assessment forNuclear Power Plant Applications",
American Society of Mechanical Engineers and American Nuclear Society, 2009.3. U.S. Nuclear Regulatory Commission, An Approach for Determining theTechnical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, Regulatory Guide 1.200, Revision 2, 2008.4. PTN-BFJR-00-001, PTN PRA Model Update, Revision 10, 7/16/12.5. PTN-BFJR-11-009, Turkey Point Internal Flooding
: Analysis, Revision 0, 8/21/13.6. Turkey Point Plant Units 3 and 4 Probabilistic Risk Assessment Individual PlantExamination Submittal, 6/25/91.7. Individual Plant Examination of External Events for Turkey Point Units 3 and 4,June 1994.8. Turkey Point Nuclear Plant Units 3 and 4 Fire PRA Peer Review Report UsingASME PRA Standard Requirements, April 2010.9. Follow-on Fire PRA Peer Review Against the Fire PRA Standard Supporting Requirements from Section 4 of the ASME/ANS Standard for the Turkey PointNuclear Plant Units 3 and 4 Fire Probabilistic Risk Assessment, Westinghouse, May 2012.10. Enclosure "Safety / Risk Assessment" to NRC Internal Memorandum, P.Hiland(Chairman of Safety/Risk Assessment Panel for G1199) to B.Sheron (Director RES),
 
==Subject:==
 
Safety / Risk Assessment Results for Generic Issue 199,"Implications of Updated Probabilistic Seismic Hazard Estimates in Central andEastern United States on Existing Plants,"
September 2, 2010.11. Turkey Point Units 3 and 4 License Amendment Request for Extended PowerUprate, August 2010.12 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.F&O # ee j Possible Resolution
.Plant Responseor Resolution Review R.spons.11AS-1WOG2002The following items were observed relatedto the success criteria:
(1) For small -small LOCAs where highpressure recirculation fails, the ECA-1.1(Loss of ECC recirculation) actions to refillthe RWST via the CVCS and continueinjection are modeled.
If this succeeds, themodeled endstate is successful corecooling.Although crediting the action is valid, thesequence as modeled has not necessarily reached a stable end state; additional action in the long term is required to putthe plant in a stable state. For example, theRWST refill can be argued to extend theaccident sequence mission time past 24hours and therefore beyond the currentLevel 1 PRA model scope. If the additional time were long, then in taking credit forthese strategies the impact on pump andother component run failures, and anyadditional actions to achieve a stable stateshould be modeled.
In addition, someevaluation should be included regarding potential effects on containment instrumentation or components ofincreasing water level.(2) For ATWS sequences where "Reactivity Control Late" is asked, the model credits(1) Perform a more explicitevaluation of the RWSTrefill function to documentthe ability to achieve astable state end state.(2) Consider revising thecharging pump modeling tobe consistent with plantprocedures.
(1) For the small-small LOCA sequences where RWSTis credited, secondary cooling is available.
Therefore, it is a virtual certainty that depressurization will takeplace and the leak rate reduced such that RWST refillis viable. In most of these sequences, some fault(s) inthe RHR system is preventing successful recirculation or shutdown cooling.
While RWST refill may not beconsidered by some as a stable state, the small flowrate associated with a depressurized small-small LOCAand successful RWST refill makes it fairly stableregardless.
The concern over extending the missiontime beyond 24 hours is offset by the increasing probability of recovering hardware failures in thecutset which prevented initiating recirculation orshutdown cooling.
: Further, if RWST refill fails, HHSIfrom the opposite-unit pumps and RWST is available.
(2) The charging pump success criterion has beenchanged to 1/3 charging pumps for emergency boration.
13 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.Peer* Description Possible Resolution
.Plant. 'o or Resolution emergency
: boration, per procedure FR-S.I.The procedure, and plant trainingdocuments, indicate that 1 of 3 chargingpumps are needed to ensure at least 60gpm of borated injection for shutdown.
: However, the fault tree model (at gateU3WRCL1) implements this as failure if anysingle charging pump fails. This is incorrect and should be fixed.AS-2 WOG Several inconsistencies between the success Revise the Accident The updated Accident Sequence Analysis
: Notebook, 2002 criteria as stated in the Accident Sequence Sequence Analysis the new Success Criteria Calculation (PTN-BFJR Analysis Notebook and the linked fault tree Notebook and/or the 014), and the updated Revision 9 PTN PRA modelmodel. Specific examples are: linked fault tree model to (PTN-BFJR-00-001, Rev. 9) resolved thea. The Small-small LOCA success criteria for ensure consistency inconsistencies.
early core heat removal is listed in Table 3 between theas 2/4HHSI pumps and 1/3 AFW pumps. documentation and theHowever, fault tree gate GIPMP3 shows 1 success criteria modeled inHHSI pump required for small-small LOCA. the linked fault tree.b. The Small LOCA success criteria for earlycore heat removal is shown as 2/4 HHSIpumps OR 1/2 RHR and depressurization.
: However, section 4.1 of the AccidentSequence Analysis Notebook and fault treegate U3S2CD2 only credit HHSI.c. The Medium LOCA success criteria forearly core heat removal is listed as 2/4HHSIpumps in Section 5.1 and Table 5 of theAccident Sequence Analysis Notebook.
14 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or 'B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.* :Peer
:: " ..: ..F&O # Description Possibe Plant Response orResolutin R e v i e w .. ..a n, .." ..... .: ..However, fault tree gate G1PMP3 and thesupporting MAAP analyses from the IPEshow only 1 of 4 HHSI pumps to berequired.
: d. The success criteria for early core heatremoval using the AFW system is described differently in the PTN System AnalysisNotebook and the Accident SequenceAnalysis Notebook.
The fault tree modelingappears to be generally consistent with thecriteria stated in the System AnalysisNotebook.
For example, the SystemAnalysis Notebook states that for ATWS, theAFW system must supply flow from 2 AFWpumps through all six AFW control valves. InTable 8 of the Accident Sequence AnalysisNotebook, the ATWS success criteria forAFW is stated as 2 AFW pumps to 3/3 SGs.The structure of fault tree gate A0201agrees with the System Notebook criteriarather than the Accident Sequence AnalysisNotebook.
Similar differences were noted inthe success criteria descriptions related tothe heat removal requirements for theTransient and Small-small LOCA sequences where the Accident Sequence Analysis onlygives the pump success citeria withoutincluding the requirement to provide flow15 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.F&O# KPeer Derito osbeS # .Description
.Possible Resolution, Plant Response or Resolution through at least 3 of 6 flow control valves..
..........
AS-3WOG2002The Accident Sequence Analysis Notebooklists several systems available to providevarious success criteria which are notcredited in the linked fault tree. Forexample:a. The Transient success criteria for longterm core cooling does not credit RHRShutdown
: Cooling, Low-head Recirculation, RWST replenishment with continued HHSI,Depressurization with Low-head injection and low-head recirculation, continued charging with RWST replenishment, orcontinued HHSI with opposite Unit RWST.b. The Small-small LOCA success criteria donot credit Bleed and Feed and the long-term cooling success criteria does not creditlow-head recirculation or continued HHSIusing the opposite unit RWSTc. The Small LOCA success criteria for earlycore heat removal does not creditdepressurization and Low-head injection.
Inaddition, the long-term cooling functiontakes no credit for RHR cooling, low-headrecirculation or opposite unit RWST.Consider removing non-credited systems from thediscussion of systemsavailable to meet criticalsafety functions in theAccident SequenceAnalysis Notebook ormodel the appropriate alternate systems in thelinked fault tree.Continued HHSI using the opposite unit RWST is nowcredited for long-term cooling of transients.
RWSTreplenishment is not credited, based on the judgmentthat the leak (2 PORVs worth) is rather substantial, and no secondary cooling is available.
The remaining options may be viable, but have many of the samehardware dependencies as HHSR, and consequently will make little difference and will not be added.As for small-small LOCA, continued HHSI using theopposite unit RWST has been added. The addition oflow-head recirculation with depressurization wouldhave little effect due to shared dependencies withHHSR and, therefore, will not be added. Credit forbleed-and-feed cooling for the SIB sequences hasbeen added to the model.For small LOCA, continued HHSI using the oppositeunit RWST has been added. As for the addition of theother options, the addition of low-head recirculation with depressurization would have little effect due toshared dependencies with HHSR, and credit fordepressurization and low-head injection was notmodeled due to the reduced time available because ofthe larger break size (2-6").The suggestion of removing mention of other, non-16 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.Peer K'"Description sIleResolution Plant Response.or Resolution i ew .H I ..., : , ....:' : -: :AS-4.............
.. ... .. ......WOG2002Event sequence transfers for the following may be conservative:
: a. The Small LOCA event tree includes atransfer to ATWS on failure of reactor trip.However, analysis at similar plants haveshown that core voiding and boron injection from HHSI will shut down the reactorwithout rod insertion for similar plants.b. The SGTR event tree was revised duringthe review visit. The new SGTR event treelogic was reviewed.
The revised logicappears to be appropriate and generally consistent with plant EOPs. Given that theSGTR is essentially a small LOCA outsidecontainment, Turkey Point does modelRWST Refill. Core damage sequence, U3RCD2, may be somewhat conservative.
Given secondary heat removal (B) andsteam generator isolation (SGI) there will bea gradual RCS cool down anddepressurization with, as a minimum, steamrelief via the main steam safety valves. Theinitial SGTR leak rate is typically in the 400:pm but this decreases rapidly to about 100.pm as the RCS depressurizes to the HHSIPlant-specific, realistic thermal hydraulic analysesmay result in elimination ofcurrently modeled coredamage sequences.
If it isdecided to retainconservative successcriteria, the reason for thisdecision should bedocumented in theAccident SequenceAnalysis Notebook.
modeled alternative from the AS notebook will not betaken. Removing them would only be removinginformation that may be useful in the future.a) No change necessary.
Presently, it is an extremely small contributor to risk.b) No change necessary.
Presently, it is an extremely small contributor to risk.17 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.F&OP#D escription Possible Resolution Plant Response or Resblution Review.....
j............................
....setpoint as a result of the SGTR. Assumingthe leak rates remains at about 100 gpm,RWST refill within the 24 hour mission timewould not be required as long as theremaining RWST inventory when the leakrate reaches 100 gpm exceeds about200,000 gallons.
(33 hours at 100 gpm).AS-5WOG2002Several items were noted regarding theATWS model:(1) The Turkey Point PRA model assumesthat ATWS is always the result ofmechanical failures (control rod insertion
: failure, trip breaker failure to open), suchthat a reactor trip signal will occur. Themodel therefore ignores the possibility offailure of automatic actuation of AFW andturbine trip; AMSAC is not modeled as beingneeded for these functions.
The Accident Sequence notebook statesthat "mechanical failure is the principal cause of the control rods failing to insert,"and implies that failure of the reactor tripsignal is not modeled.
: However, there is arandom failure "LOGIC CIRCUIT FAILS TOGENERATE SIGNAL" (a different gate foreach train) that is input to each "TRIPBREAKER RT FAILS TO OPEN" gate. It is notclear what portion of the reactor protection Consider adding explicitmodeling of the RPSequivalent to that providedfor the ESFAS logic and:onsider adding systemmodeling for AFW to3ccount for variations inthe success criteria forsecondary heat removal.1) The RPS model in the PTN PRA is deliberately simplified.
With the myriad of redundant systemswhich can trip the reactor, coupled with the furtherredundancy of the operating crew to manually trip theplant based on indicated parameters, it was deemednot worthwhile to produce a detailed model of theRPS. An AMSAC model was added to the PRA.2) No changes made. The potentially conservative modeling of the recirculation failures in AFW forATWS is not a major contributor to CDF, so it was leftas is.3) A new ATWS event tree was created using theguidance in WCAP-15831-P-A, WOG Risk-Informed ATWS Assessment and Licensing Implementation
: Process, Revision 2, August 2007. ATWS top eventfault tree logic was developed using the new ATWSevent tree.18 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.Peer Ie rit n ; : ; ,:oF&O # ee scription Possible Resolution Plant Re on' or Resolution Review n~~~rRslto
.,.._.._.,:__._____.___._.._.______...
___.. _ I. ,___ ___ ___ __system is intended to be represented bythese logic circuit gates. Further, commoncause failure is not explicitly addressed forthese gates, although there is a commoncause failure "TRIP BREAKERS FAIL TO OPENDUE TO COMMON CAUSE"; it isn't clearfrom the available documentation whetheror not logic circuit common cause isincluded in this event. Further, it isn't clearthat the possibility that signal failuresleading to failure of both reactor trip andAFW startup or turbine trip, such thatAMSAC actuation would be needed, havebeen addressed in this manner.Development of a more detailed description of the ATWS fault tree logic should beconsidered.
(2) The AFW logic for ATWS sequences, where 2 pumps are required to provide flowto 3 steam generators, includes pumpfailures due to recirculation (i.e., "mini-flow") failures (e.g., Gate A0010). While thismay normally be a valid failure mechanism for these pumps, it would seem that, withthe high flowrates required for ATWSresponse, it would not apply under theseconditions.
Consider reviewing the basis forthis modeling and correcting if necessary.
(3) The Turkey Point ATWS model is19 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.MO # Pe Descito Possible Resol~to Plant Response brResolution, F # ~Review srpinuin*o
:_" _ _" .... II 2 .. ... ..;. ':.. .__ _.__ _ _ _.__ _ _ _.__ _._ _ ._ _ ......-1 1. .'. .' .=.= ...osignificantly different than the WOG ATWSmodel presented in WCAP-11993 (andcurrently being updated for the WOG).Consideration should be given to adoptingthe revised WOG model after it iscompleted and reviewed by NRC.AS-7WOG2002WOG2002The SGTR event tree branches to the ATWStree on failure of reactivity control.
TheATWS tree does not address the secondary side isolation and depressurization neededto mitigate an SGTR.Consider discussing this inthe ATWS or SGTRwriteups to providejustification for notincluding this logic (i.e.negligible impact.)The SGTR frequency is 3.2E-03 per year. Couple thatwith the pre-eminent ATWS "failure-to-scram" cutsetof NRDPHYSICAL, the physical failure of the rods to fallin the core" with a probability of 1.2E-06, and beforeyou have considered the probability of other failuresnecessary for core damage, you are already at afrequency of 4E-09 per year. SGTR does appear in theATWS top logic as an initiator but it is true that theATWS top logic does not take into account the specialrequirements to mitigate a SGTR. However, to includesuch logic would have no appreciable effect on thequantitative results of the model, baseline orconfiguration-specific.
The ATWS event tree was upgraded in the PTNAccident Sequence Analysis for RG 1.200 usingguidance in WCAP-15831-P.
In this WCAP, it statesthat current studies have indicated that the SG tubeswill withstand an ATWS pressure peak that results inRCS failure.AS-8The potential for an induced SGTR is notaddressed in the ATWS model. Nor is itaddressed for the transient modelassociated with main steam line break.The accident sequencenotebook should beupdated to include aqualitative discussion ofthe basis for excluding induced tube ruptures.
AS-9WOG The SGTR event tree does not have Ensure that there iscomplete sequence delineation.
For the sufficient basis for th,The SGTR event tree was revised such that no creditB for RCS cooldown and depressurization is given for20 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.F&O # .: Peer ]Description
."' ..Possible Resolutnio Plant Response or Resolution
.:Review.
2002 case with failure of isolation and failure of modeled accident sequences where SG isolation and HHSI fail.HHSI, cooldown and depressurization to sequences.
RHR conditions is asked and, if successful, no further delineation is provided in themodel. There should be some T/H analysisto show that the plant can be cooled downto RHR entry conditions without HHSI givena SGTR.DA-1WOG2002DA-2WOG2002NUREG/CR-4550 was followed to developCCF. NUREG/CR-4550 was issued in 1986.The approach addressed in NUREG/CR-4550 may have been out of date. NUREG/CR-4780 (or equivalent) systematic approachshould be followed.
The test and maintenance probabilities used for individual components are basedDn actual outage time as collected by theplant. The component outage time wasclearly collected over the period of time theplant was in Modes 1, 2, and 3.The fault trees and event trees use severalcross-ties from AC power, HHSI, and AFW.In the use of these cross-ties, the oppositeunit components have T&M events. TheConsider revising CCFmodeling based on theNUREG/CR-4550 systematic approach.
Amore updated systematic approach (such asNUREG/CR-4780 orequivalent) should befollowed.
Consider revising the T&Mevent probabilities for theopposite unit components to account forunavailability over the totalperiod of demand. Asstated above, this can bedone at the fault logic levelor in the data probabilities.
The Turkey Point CCF model was updated to reflectthe alpha-factor approach and data from INEL94/0064.Logic was introduced to the model to change theopposite-unit EDG testand maintenance probability during outage conditions through the use of flagsrepresenting the operating mode of the unit. Theseflags were also used to model the effect of theopposite unit's mode on the different systemcrossties.
21 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.Reie Description Possible Resolution Plant Responseor Resolution
*opposite unit may be in Modes 4, 5, and 6at the time of demand and the desiredequipment may have lesser Tech Specs thanthose assumed for power operation.
TheT&M event probabilities for the oppositeunit components must considerunavailability over the total period ofdemand, not just during power operation.
This can be done at the fault logic level(with house events for OOS) or in the dataprobabilities.
Currently, neither is done.The most important case of this is the DG's.The DG T&M unavailability is about 6E-3 (55hours per year). If the OOS time for majoroverhaul were considered, theunavailability would be .03 to .05.DA-3WOG2002There is no clear guidance for component boundaries and grouping.
The Bayesianapproach addressed in the Data ProcessProcedure is inconsistant with the approachapplied in Rev 4. In the data processprocedure, the lognormal distribution willbe convered to alpha and gamma first, thenperform Bayesian updating.
In Rev. 4, IP6, 7,B, 9 updating in Rev. 4 are not following themethod addressed in the procedure.
Consider updating the dataprocess procedure to beconsistent with theapproach applied in Rev. 4.Component boundary definitions and consistent Bayesian updating are part of the latest data update(PTN-BFJR-02-026, Rev. 1).DA-4 WO G The latest data updating was done in 1995 lReview industrial events I'he data used in the latest model update has plant-22 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.Peer P... , D Possible Resolution
: Plant Response or Resolution Review scptoIOHa..sne 2002 based on plant specific data from 1990 to after 1989 to update the specific data derived from plant records from 19921994, and the generic database developed generic database and through 2006, and generic data from the latest.in 1989. update the reliability data sources, primarily NUREG/CR-6928.
based on current plantspecific data.DA-5 WOG Loss of 4kV buses A and B are modeled as Remove maintenance The normal power supply to 4KV buses A and B is not2002 special initiating events. The normal power events for components the startup transformer, but the auxiliary transformer.
supply to these buses is Startup which cannot be removed The startup transformer supplies power to the 4KVTransformer 3 with emergency power from from service during at- buses only if power from the aux transformer is notthe diesel generators.
Since loss of power to power operation.
If these available, such as following a reactor trip. Therefore, 4kV Bus 3A or 3B will result in a plant trip, it events are required for the startup transformer can be removed from serviceis unclear that maintenance would be maintenance rule during power operation, and occasionally is.*performed on the startup transformers performance criteriaduring at-power conditions unless there are sensitivity
: analysis, then itunmodeled crosstie arrangements during should be confirmed thatthe maintenance.
It was noted that the all such events are set falsemaintenance events for the 4kV buses false in the baseline(ETM3A4KV and ETM3B4KV) are set false quantification flag file.prior to quantification.
It would seem thatthe same should be true for eventETM33SU.
This might be negligible, exceptthe the maintenance unavailabilities arealmost two orders of magnitude greaterthan the random failure of the transformer.
DA-8WOG2002The diesel FOT pump is not explicitly included in the PRA. It is stated that the FOTis assumed within the failure events for tankVerify the component boundaries of the day tankand IDG so that it is clearrhe pumps do not have to be added to the model forthe U3 EDGs as the U3 day tanks gravity-feed theEDGs, and have enough capacity (4,000 gallons each)23 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.F&O # Pee escriptioni
: ;; .Possible.ResolutionK
; j Plant Response or Resolution**
failure.
While this may be true, the CCF of where the FOT pump is to supply their respective EDGs for the entire missionthe FOT pumps is therefore not included, subsumed.
Verify that CCF time. The situation for U4 is different as each day tankbecause there is no CCF for the daytanks, of FOT is similarly only contains 650 gallons.
Therefore, the fuel oilsubsumed in the higher transfer pumps were added to the model for the U4component.
EDGs.DE-2 WOG The Flooding analysis considered Review flooding analysis to The internal flooding analysis has been completely 2002 *component vulnerability to both flooding determine if the screening revised for RG 1.200. See Calculation PTN-BFJR and spray effects.
Multiple screening and flooding initiator 009, Rev. 0.criteria were employed to eliminate areas frequency calculations arefrom further consideration.
The three still current using updatedremaining areas were then analyzed in methodology, models andmore detail to determine a CDF from assumptions.
flooding.
A CDF of approximately 5E-7 was calculated for flooding and determined to be notsignificant relative to then overall risk (IPECDF of 3.7E-4).
The current model maintains cutsets of lower CDF than these floodingcutsets.
The conclusion that the flooding isnot significant is no longer supported.
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IE-1 WOG *The PTN PRA updates are not documented Develop integrated As part of the RG 1.200 effort, notebooks were2002 in a single document.
There is not a single IE notebooks with all prepared for each 'part of the PRA update process:
AS,system notebook that contains all pertinent revisions.
IE, SC, HRA, etc.information and references for the IE task.The basis for the current PRA is some casesgo back to the 1991 IPE. Updates have been_performed as needed. Each update is24 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.: ".i *Peer .. = ' .. :.": ";,:PPe #Desp Possible Resolution Plant Response orResolution Review..cription IE-2WOG2002documented as it is done and filed by timeof update, not subject matter. It was verydifficult to find the current status of ananalytical issue.The disposition of dual unit initiators anddual unit success criteria is not clear. Thefollowing observations were made:1) Loss of grid is called a "dual unit initiator" with a frequency of 0.053. The derivation for 0.053 is dominated by switchyard faults,which the IPE notebook implies would be asingle unit initiator.
: 2) Loss of a DC bus on either unit willrequire the other unit to shutdown, but it isnot explained why this is not a dual unitinitiator.
: 3) There are no guidelines for dual unitsuccess criteria.
There are several shared systems at PTN.The success criteria for Unit 3 assumecomplete availability of the Unit 4 systemsto mitigate events at Unit 3. There shouldbe an identification of dual-unit initiators and development of associated dual-unit success criteria.
Clarify the nature of dualinit initiators and dual unitsuccess criteria within thePRA.1) The LOOP initiators are now split into 5 different nitiators.
There are 4 dual-unit initiators:
plant--entered, weather-induced, grid-related, and gridblackout; and 1 single-unit intiator.
The two unitsshare one switchyard, so it is assumed that switchyard Faults cause a dual-unit LOOP. The single-unit LOOP isdominated by unit-specific startup transformer faultswhich are on the periphery of the switchyard andcause a loss of offsite power to only one unit.2) This is because the other unit would have to shutdown due to Tech Specs. As such, it would not be animmediate reactor trip, but a controlled shutdown.
: 3) Dual-unit success criteria are discussed fully in theAS Notebook and the SC calculation PTN-08-014.
Theeffects of the dual-unit initiating events on theopposite-unit systems are modeled.Added RV Rupture IE in PTN-04-011.
Research overthe last few years by NRC, EPRI, DOE, MRP, and othersIE-3WOG2002The initiator for Pressurized Thermal Shock Provide justification foris considered "out of scope" with no elimination of these25 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.i Resolution.
Plant Response or Resolutioni Fevi e s ...,. ..*.I E-4WOG2002ustification.
PTS is not out of scope for PRA.Discussion with PTN PRA staff indicate thatfrom a licensing perspective, it has beendetermined to be a resolved and therefore should not be in the PRA. This should beexplained, with a probabilistic explanation
*of why it is a small contributor.
The initiator for Reactor Vessel Rupture isconsidered out of scope with noustification.
PTN has several shared systems.
Theseinclude HHSI, AFW, and DG. Theconfiguration of these systems may dependon the status of the unit. For the purpose ofsystem sharing, the opposite unitequipment is always assumed to beavailable in Mode 1 operability.
The following observations were made:1) The T&M unavailability for DG impliesabout 50 hours a year OOS. This can notinclude time for annual overhaul, (which isdone at shutdown).
When the opposite unitis in Mode 6, the DG tech spec is reduced to1 DG. The PRA does not capture thisdependency on plant status.2) When Unit 4 is in Mode 5 or 6, the HHSIfor unit 4 is cooled by CCW on unit 3. ThePRA does not capture this.initiators or include inmodel.Develop and implement criteria for modeling dualunit plant operating status.has shown PTS to be a non-issue for plants like TurkeyPoint.See resolution of DA-2 for 1) and 3). 2) is addressed byPRA Change PTN-02-005, which is implemented in thecurrent PRA model.26 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.Peer Possible.Resolution
=Pl.ntF&O .# Description
.Possible Resolution Plant Response or Resolution Review _____'"3) there are no overall guidelines andcriteria for treatment of the opposite unit'soperability and it's affect on equipment availability.
IE-5 WOG There are several methods for quantifying Consider creating a See Initiating Events Notebook, Rev. 3 and PTN data2002 IE frequencies.
They are derived from a) summary table consisting update calculation, PTN-BFJR-02-026, Rev. 1.plant specific experience, b) NUREG/CR-of initiating event category, 5750, c) plant specific fault trees, d) CE frequency, andOwner's Group for LOCA's. It was not quantification method.possible to find, in one place a summary ofthe quantification methods.IE-7 WOG The level of independent technical review Provide evidence of an There is now a comment and resolution section in the2002 of PRA changes is indeterminate.
There are independent technical model update calculations.
no comment and resolution sheets for the review. Document howPRA modification process.
There is only a review was conducted andsignoff sheet on the overall update package what comments were(which contains several individual changes).
made during the review.IE-8WOG2002The system notebook states that MSIVClosure and Loss of condenser vacuum areclassified as a Reactor trip with full MFWavailable.
There are 2 issues on which thiscould conflict.
: 1) The availability of condensate water maybe affected by loss of condenser, but thestaff states that there are 2 CST's withmake-up and transfer capacity.
: 2) the operability of steam relief from theProvide a basis forzlassifying MSIV Closure3nd Loss of condenser vacuum as Reactor tripvvith full MFW available.
The PCS system notebook no longer makes thisstatement.
: However, the statement is irrelevant asthe determination of the IE frequency for LMFW issolely based on actual plant-specific and industryexperience.
Steam relief of the SGs is modeled.27 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.Pveerv> 'F&O# D Possible Resolution Plant Response or Resolution, Review Dsrpino~eouin SG, whioch is not modeled in the PRA.The basis for classifying these IE as reactortrip is not given. But, the affect on theresults (if this is misclassified) is notimportant because the frequency for the IEare derived based on industry and plantspecific data and do no account for eachindividual category.
IE-9 WOG Random reactor coolant pump seal failure Include random RCP seal A review of NUREG/CR-5750 revealed that the2002 has not been included.
From NUREG/CR-LOCA as an initiator, random seal LOCA frequency is 2.5E-3 per year, and is5750, this event can be about 1E-3. The Si based on 2 events: a 1975 event at Robinson-2, and afrequency is derived from pipe rupture 1980 event at ANO-i. The incident at ANO-1 can befailures only. It does not include component discounted not only due to the fact that it was 20leakage, RCP seal LOCA, or any other years ago and design changes have likely been madesources of small leakage.
to preclude similar events, but also due to the factthat ANO-i is a B&W plant with substantial differences in RCP and RCP seal design. The incidentat Robinson-2 was discounted due to changes in sealdesign and seal-related operating practices andprocedures implemented in the last 37 years.MU-1 WOG Performed a quick review of the PRA2002 Change Access database:PRAUPDATELOG.mdb with help of TurkeyPoint PRA staff. Searched the PCN tableuntil a PCN which had a PRA impact wasfound. This PCN, 94131, involved a changeto remove a valve, CV-4-32202, and replaceCloser adherance toprocess.Fixed. Should have been PTN-03-026.
28 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.iD: n.I ...."m ni......
"I " ' =; " " "' "F&O # Description
..R Plant R Resolution VReview josE~ns~Lo epneoit with a spool piece. This PCN pointed toPTN-99-026, which in turn pointed to PTN-BFJR-99-010 for final resolution.
PTN-BFJR-39-010 was the update of the level 2analysis and did not discuss the valvechange at all. Additional investigation revealed that PCN 94131 should havepointed to a different PRA change form andcalculation.
.... ... ...... .MU-2WOG2002STD-R-001 has a requirement for signoff bythe preparer, an independent reviewer andthe RRAG supervisor.
The PRA updatecalculations that were reviewed had all therequired signatures.
However there wereno review notes or discussion of thedisposition of review comments in thevarious calcs examined by the peerreviewers.
: Further, the peer reviewers found examples of inconsistencies in severalsigned-off notebooks (e.g., AccidentSequence Notebook included incorrect success criteria for S2 LOCAs), and examplesDf errors carried through several PRAUpdate Calc revisions (e.g., CDF cutsets thatincluded single failures in emergency boration pumps for ATWS, which shouldhave required multiple failures).
Consider augmenting existing RRAG processes bydefining such measures asa standard, expanded levelof detail in description ofPRA changes beingincorporated, items to bechecked for by reviewers, etc. In particular, thepurpose/basis for eachchange should be definedin the change packages.
This should provide thereviewer with enoughinformation to determine ifthe detailed changesactually are sufficient tofully address the basis forthe change.There is now a comments and resolutions section inthe model update and other PRA Group calculations.
Details of each change are documented in the PTNChange Database.
Each model update includes a tableof the changes implemented for that model updateand reasons for those changes.Consistency issues between the Accident SequenceAnalysis, the Success Criteria calculation, and themodel update calculations have been resolved in RG1.200-related upgrades of all of these documents.
The other issues are treated separately in other F&Os.29 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.PFe& Description Possible Resolution.
Plant Response or Resolution Rei ew ..esponseorResolution_.
... ..____:_ _____MU-3WOG2002Procedures STD-R-001, Rev. 0 (Software Control Procedure) and STD-R-002, Rev. 5(Update and Maintenance) govern modelcontrol.The computer models (e.g., current andprevious model files such as *.CAF and *.BE)for the Turkey Point PRA are maintained ona server (g:nis\PSA).
The server is backed updaily and therefore provides secure storage.Access to files on this server is limited tothose with permission and is on a read-only basis. In addition, computer models arestored on a CD and sent to the documentcontrol center. A second copy is maintained locally.
Model changes are also maintained on this server.This same process is used for the PRAsoftware (e.g., EOOS, CAFTA, FORTE).NAMU-4WOG2002STD-R-002 requires a data update every 5years. However, it does not appear thatTurkey Point has updated the reliability data since 1995 even though the commoncause failure data, the human factors data,the initiating event data and theunavailability data was updated in 2000.Update the reliability data.Ensure adherence toprocedures Data updated in current PRA model using the datadocumented in the data update calculation, Rev. 1 ofPTN-BFJR-02-026.
MU-5WOG2002STD-R-002 includes a set of criteria forwhen to perform a model update. The keyRevise the procedure, STD- Changed procedure to have a maximum interval ofR-002 to incorporate a five years between model updates.30 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.Peer ~1F& .Dscription
~ Possible
-Resolution 1Plant .Response or Resolution.
~~iReview criteria are if the change has a significant impact on CDF or risk insights.
However,there are no criteria as to what constitutes a significant impact. Given that there is nofixed update period, there is a concern thatthe number of "minor" changes pending:ould build up until the combined impact issignificant without triggering an update.fixed update equivalent tothe fixed data updateschedule to preclude anunending build up minorchanges that could have asignificant cumulative impact. The procedure should also be revised toinclude a process forevaluating the potential cumulative impact ofpending changes andtriggering a model updateif the cumulative impact ofthe pending changes isjudged to be significant Whether minor changes constitute justification for amodel update is determined by the model custodian.
MU-6....... ....... .......... .. ..-.. ...... .......WOG2002Turkey Point does not appear to have asingle list of "Living PRA Applications" Establish a controlled list ofPRA applications and revisethe procedure to require atleast a qualitative evaluation of allapplications on the list beperformed anddocumented following each model update.Those transients whichresult in a 21 gpm leak rateList added to STD-R-002 (see Table 5).Transient initiators are input to all of the transient sequences.
QU-1WOG2002Loss of RCP seal cooling sequences following transient initiating events are31 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.IPeer .1Desciption Possible Resolution
: Plant Response or Resolution transferred to the S1 LOCA event tree with would be treated asa ZZSL flag event set to 2.1E-1. However, it normal transients andis not clear that the 79% of loss of seal would be accounted for incooling events resulting in 21 gpm per the transient sequences.
pump seal leakage are being retained in thetransient event sequences.
....__._.._.........__..............___
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...._____________________________________
.QU-10WOG2002The truncation limit for the CDF results isconsistent with the grade 3 requirements, but the same core damage results are usedas the basis of determining the LERF. Thiseffectively results in the LERF truncation level being less than 1E-4 below the totalLERF.givensensitLERF t3pplicmpor.. .............. ................
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....... ..QU-2 WOG The guidance provided for the Consii2002 quantification process is IPE vintage.
Several guidainew codes are being used in the current of muprocess which did not exist at the time of combthe IPE. No guidance procedures currently develiexist to control key processes involved in contrmodel integration and quantification such systeras: detera. Criteria for development of the mutually approexclusive events file level,b. Selection of truncation value input,c. Quantification on a sequence basis versus uncerquantification of top gated. Process for breaking circular logic in thederation should beto performing ivity studies at lowerruncation levels forations where LERF is-tant.der establishing clearnce for the selection tually exclusive eventinations, the use andopment of flag files tool the quantified n configuration, themination of anpriate truncation and acceptable sfor performance oftainty analysis.
In the Rev. 9 PTN PRA model, the Level 2 model isincorporated directly into the fault tree and quantified separately.
The truncation for the quantification ismore than 1E-4 below the mean LERF value.Changes to the mutually exclusive eventcombinations, flag file, and recovery rule file that haveoccurred since 1998 are documented in the PTNChange Database and the model updates.
Theydocument the mutually exclusive event combinations, flag file, and recovery rule file with justification fortheir content.
Truncation level is set as low as thehardware and software will allow, or untilconvergence is achieved.
Uncertainty analysis input isdescribed in the model update calculations.
32 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.Peer ' Pb" Pl" .:.- # ... =. Description Possible Resoluton Plant Response or Re tionReview, I :.RsosrRslto single top linked fault tree (i.e., selection ofproper gate level for performing the logicalbreak, naming scheme to be used for gatesin the new system fault tree, etc.e. Process for development of flag files forthe baseline quantification to ensure thequantified configuration represents normalplant operation practices
: f. Selection of parameters for input to theUNCERT code for uncertainty calculation QU-3WOG2002The quantification of a linked fault treemodel involves the proper integration ofseveral files which can affect the results.
Forexample:a. The quantification flag file is used to setlogic flag events true or false to represent normal system alignment.
At PTN, this flagfile is also used to set certain maintenance events false.b. The mutually exclusive file is used toremove cutsets from the results file whichcontain certain combinations of eventsrepresenting disallowed maintenance orillogical event combinations (i.e., events forfailure to open and spurious opening of thesame valve in a single cutset).c. The recovery rule file is used to addrecovery events to the cutset results asedConsider developing adocumentation packagefor the flag file, mutuallyexclusive events file andthe recovery rules whichprovides the basis of eachitem in the respective files.Cross-disciplinary review ofthe flag file and mutuallyexclusive events file byplant personnel may alsobe considered.
See QU-2.33 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.PeersieReouinPnt.
F&O-# .Description.
.Possible Resoplution Onse or Resolution
_______ Review~ ____________________________________________
t '
........
: :; ' I ,.,... ._. :...:_...__
_ ..__ _ ..._......_
_ _..._ _ _ _ _ _ _ _ .on the appearance of certain combinations of failure events. At PTN, this process is alsoused to apply human error factors to thequantification results.Since these files control vital processes during quantification, independent reviewand thorough documentation is needed toensure that the quantification results do notexclude valid failure sequences.
The currentmutually exclusive events file(PTN2KMEE.TXT) was changed as a result ofthe addition of new T&M events forLC/SWGR HVAC AHUs and Sump LevelIndicators.
The calculation package includesa description of "add double maintenance events for these basic events to mutuallyexclusive events."
: However, no justification for making the events mutually exclusive orspecifying the combinations that aremutually exclusive is provided.
In addition, the review of the mutually exclusive eventsfile indicates that some complimentary combinations related to AFW pumpmaintenance may not be included.
Whilethis would lead to conservative results dueto failure to remove invalid cutsets, theaddition of inappropriate mutually exclusive combinations would have the oppositeresult. Similar errors can be introduced 34 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.'Peer VF&O 4" Description Possible Resolution ePlantResponse or Reslution R e ie e ie_. ." ....." .. ......... .. ... ....."r 1 "_____..
.. _ "'___" " _______ "... .' '.:.~ ! ":.[QU-4WOG2002through the recovery file through theinappropriate application of recoveryevents to sequences which do not represent the conditions assumed in the HRA analysis.
The current practice is to run the baselinequantification with the flags set to use LoopA as the broken loop for LOCA events. Fromdiscussion with PRA group personnel, thiswas decided based on evaluations duringthe IPE which did not identify anyasymmetry due to broken loop andoperating equipment alignment.
However,there was no evidence that this evaluation has been performed since the IPE to ensurethat plant changes and changes to thelinked fault tree have not inadvertently introduced asymmetry.
Consider performing futurequantifications with flagsset to split fractions ratherthan True or False. This willensure all complimentary cutsets appear in thequantification results andprovide an opportunity toidentify any asymmetry introduced through plantmodifications or modelupdates.The flags are now set to split fractions.
In the PRA model updates, sensitivity analyses are runto show the effect of key modeling assumptions.
Parametric uncertainty is addressed in the modelupdated calculations.
Comprehensive uncertainty analysis evaluations are provided in the Uncertainty Analysis Notebook.
QU-5 WOG Documentation was not available to2002 indicate that PTN has performed qualitative evaluation for causes of uncertainty, suchas:a. possible optimistic or conservative success criteria,
: b. suitability of the reliability data,c. possible modeling uncertainties (asymmetry or other modeling limitations due to the method selected),
... .. .................
To meet the grade 3criteria for sub-elements DaU-27 and QU-28(uncertainty analysiscriteria),
perform anddocument a moresystematic uncertainty evaluation to identifypotential uncertainties dueto such items as modeling35 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.: i ee r ::i " ".. .. ... ... .. .F&O # : Description Possible Resolution
: Plant Response or Resolution
,, It _____ ________:_____________~_
_ _ _ _ ...Q........U.-.6.....
.......QU-6WOG2002d. degree of completeness in the selection of initiating events, ande. possible spatial dependencies.
Recovery of offsite power is applied tosequences where offsite power may notrecover the lost function.
This occurs in twotypes of circumstances:
: 1) for non-grid-loss initiators, LOSP (andSBO) can occur due to failure in the ACpower distribution system. XROSPi isapplied.
The recovery probability of XROSPiis based on the NSAC document forrestoration of offsite power to nuclearplants. The sequence in question is cause bya failure of a breaker or transformer at theplant. It is not clear that the recoveryprobability is applicable.
: 2) for some SBO sequences where all SGheat removal is lost, XROSPi is applied.assumptions, successcriteria conservatisms, data, etc, Identify the likelyimpacts of these sources ofuncertainty on results, andperform sensitivity analyses as appropriate toachieve an understanding of whether/how they mayaffect risk-informed decision-making using thePRA.Verify that the recovery ofoffsite power is a)applicable, b) will recover(with high probability) thelost function, c) has anapplicable probability.
In the current model update, the recovery of offsitepower is not credited for cutsets where the recoveryof offsite power does not recover mitigating equipment sufficient to avoid core damage.Recovery of offsite power is not credited forsequences where the LOOP simply acts as a reactortrip initiator (and loss of MFW) versus a supportsystem loss.36 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.Peer. D t ~at reouoF&O # Description I Possible Resolution.
Plant Response orResolution Review " .... ...__ *_.___ ... ..._._.____
....'___ .__.....QU-7QU-8WOG2002WOG2002Adthough AC power is available, it is notclear that SG Heat Removal is restored.
The5G heat removal is provide dby 3 TD pumpsand 1 diesel driven pump. If these fail,restoration of AC power does not makethem operable.
For example, there is a cutset at 1.274E-9vvhich is loss of 4KV 3A with failure of auxtransformer.
There is a recovery for XROS19and EHFPXTIE.
The correctness and reasonableness of thispractice is questioned.
4, review of the dominant cutsets revealedthat the failure of the operators to trip theReactor Coolant Pumps following a loss ofAil cooling does not appear to be modeledin the Turkey Point PRA model. This hasbeen found to be a dominant contributor tocore damage at similar plants.The subtier criteria for a grade 3 on thiselement considers the following to beindicative of a good understanding of thedominant risk contributors:
: a. The accident sequence results bysequence, sequence types, and total shouldbe reviewed and compared to similar plantsto assure reasonableness and to identifyEvaluate the applicability of this RCP seal failuremode to Turkey Point andmodify the PRA model ordocumentation asappropriate.
Consider expanding thediscussion of thequantification results in thecalculation packages ordeveloping a PRA SummaryDocument-containing thistype of evaluation for eachrevision.
Added CHFPSTPRCP, failure to stop RCPs given loss ofCCW, to the model.a. A comparison of PTN CDF cutsets to Robinson's CDFcutset was made and is documented in theQuantification Notebook.
Where differences in thecutsets occurred, they could be explained by design ordata differences.
: b. A list of the top 50 cutsets is provided in the modelupdates.c. Initiating event pie charts, system importance
..............
.37 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.F&O # [Peer 1~clto P ~ o_#_evwscription Possible Resolution.
Plant sesponse or Resolution oRevieweoltonse any exceptions.
: b. A detailed description of the Top 10 to100 accident cutsets (CAFTA or NUPRA) oraccident sequences (RISKMAN) should beprovided because they are be important inensuring that the model results are wellunderstood and that modeling assumption impacts are likewise well known.The dominant accident sequence groupsor functional failure groups should also bediscussed.
These functional failure groupsshould be based on a scheme similar to thatidentified by NEI in NEI 91-04, Appendix B.There is no discussion of results in thecalculation packages for updates providedto the review team to indicate that this typeof evaluation is done of the quantification results.
Also, the calculation packagesprovide no discussion of how the dominant:utsets or impotant systems were affectedby the changes to the model whencompared to the previous revision.
Module GMM3GK100 contained failures for3 valves in the mini-flow recirculation lineFor HHSI 3A. Only 2 of these valves could beFound on Figure 10 on page 44 of 127 in thePTN System Analysis Notebook.
charts, and a table listing the individual sequencecontributions are included in each model updatecalculation.
Fixed in the HHSI system notebook update for RG1.200.SY-1WOG2002Update the simplified schematics to include allmodeled components orprovide some other meansfor identifying the locationof all modeled components 38 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.' : "Peer " :; :..: ; : ..." ......F&O4 .Description
'Possible Resolution ionReolutonlRenview orSY-2WOG2002The RHR/LHSI model for recirculation assumes that failure of either the RWSTlevel indication or the sump level indication will result in a failure to switchover torecirculation.
Themodel for failure of thesump level indication includes commoncause miscalibration but common causemiscalibration of the RWST level indicators is not included in the model and no basiscould be found for the exclusion of thisfailure.The CCW model does not include the reliefvalve, or the surge tank levelinstrumentation.
The discrepancy betweendefinition of dependencies in section 3.6.5 and themodel should be resolvedand the model revisedaccordingly.
Added JHFA3RWSTLVL, "common cause miscalibration of U3 RWST level indicators" to gate J504. AddedJHFA4RWSTLVL, "common cause miscalibration of U4RWST level indicators" to gate U4J504.SY-3WOG2002The level of detail for the electrical systemsis not consistent with normal industrypractice.
For example:a. Modeling of the diesel generators includes leakage from the fuel oil storagetanks and piping, but does not includefailure of the fuel oil transfer pumps. Thiswas noted as a deficiency in the Revision 1update, but no clear resolution was noted.It is implied that the transfer pump failuresare included in the tank leakage event, butthere is no documentation that has beenfound for the inclusion of the pumps in thetank boundary for data collection andExplicitly model the dieselfuel oil transfer pumps andgrid/switchyard failure.a) The pumps do not have to be added to the modelfor the U3 EDGs as the U3 day tanks gravity-feed theEDGs, and have enough capacity (4,000 gallons each)to supply their respective EDGs for the entire missiontime. The situation for U4 is different as each day tankonly contains 650 gallons.
Therefore, the fuel oiltransfer pumps were added to the model for the U4EDGs. See PTN-2-034 for addition of diesel fuel oiltransfer systems to the model.b) Switchyard failure following non-LOSP initiators isincluded in the LOSP event database.
39 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.: ,: .. ,:...F9O # R Description R Possible Resolution Plant Response or Resolution AevewPsil calculation of the tank leakage eventprobability.
: b. Only Startup transformer failures aremodeled for offsite power feeds following an initiating event. Switchyard failurefollowing non-LOSP initiating events is notincluded.
SY-4 WOG Gate E3093H models failure of the Charging Replace event ECBR335008 This has been fixed.2002 Pump 3C breaker to open on undervoltage.
with the proper basic eventHowever, the breaker failure event included coding to ensure theunder this gate is ECBR335008, Breaker correct event probability is35008 Transfers Open. assigned.
Review similarlogic gates to ensure this isnot a generic modelingconcern.TH-1WOG2002The basis for requiring or dismissing HVACrequirements is poorly supported andinconsistent throught the PRA. Thefollowing observations were made:1) The HVAC system notebook and DGsystem notebook require HVAC for EDGrooms, DC equipment room and 4160equipment rooms. The analysis is based ondesign basis calculations from A&E done in1985-1988.
: 2) Recent updates use engineering judgment and plant experience from systemConsider revising analysisto better support HVACrequirements.
The HVAC analysis has been fully revised.
GOTHICroom heat-up calculations have been performed formany of the HVAC-cooled areas containing PRAcomponents, especially those where the need forHVAC was questionable.
The heatup calculation results were compared to the survivability temperatures of the PRA components in the variousrooms and the dependencies applied accordingly, 40 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.Pee~rFO Review Description Possible Resolution Plant Response
" Resolution
..... .. Resp o rs O :ResolUtlon
:engineer to dismiss need for HVAC to 4160and DC power rooms.3) The current fault trees require HVAC forDC room and EDG room for LOCA eventsnily.4,) GOTHIC or other room heat up:alculations have not been done to supportroom cooling of these rooms.Discussions with plant staff during theCertification indicate the following requirements for HVAC:4,) Unit 3 DG does not need HVAC.B) Unit 4 DG need HVAC whenever theyDperateC) the switchgear room needs ventilation toprotect the 480v transformer.
Theswitchgear ventilation system is normallyrunning.
Remedial action via opening doorsand running an exhaust fan is sufficient tomaintain temperatures.
The lead time andindication of loss of ventilation is sufficient enough that loss of switchgear roomventilation is not considered an initiating event.D) The inverter and battery charger needroom cooling.
Remedial action is available vith plug-in, portable fans, but recovery41 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.Peer*I.".
" ' .i0 : # Description
:Possible Resolution Plant Response or Resolution Review.time is on the order of 1 hour.TH-3 WOG It is difficult to determine, from the PRA Provide clearer traceability The updated Accident Sequence Analysis Notebook2002 notebooks, which codes or methods of of success criteria to *(Revision 3), the new Success Criteria Calculation analysis are used for specific success criteria analytical bases, at least (PTN-BFJR-08-014, Rev. 0), and the updated Revision 8determination, or why these methods are for "non-obvious" criteria PTN PRA model (PTN-BFJR-00-001, Rev, 8) resolvedappropriate.
For example, applications of (e.g., for those whose basis this F&O.the MAAP code, particularly the IPE-vintage is other than FSAR).3b version, may require some justification Consider developing a clearor check for applicability (e.g., avoiding use set of guidelines of MAAP 3.0b for rapid RCS establishing the acceptable depressurization scenarios, which typically range of applications ofrequire capabilities beyond what was various types of codes andavailable in that particular version of the calculations.
code).Further, it is difficult to determine thespecific analytical bases for specific successcriteria used in the model. While theAccident Sequence Notebook includes asummary of success criteria for each event,reference for the bases for the successcriteria is to the IPE, which does not provideadditional information on this subject.TH-4WOG2002The LOCA break size definitions for the PRAare based on different criteria than thosefor most other PRAs. This is acceptable ifthe underlying analyses provide sufficient basis for the definitions.
Because the break sizedefinitions are central tothe LOCA modeling for theTurkey Point PRA, thereshould be, in the eventThe updated Initiating Events Notebook (Revision 3),the updated Accident Sequence Analysis Notebook(Revision 3), the new Success Criteria Calculation (PTN-BFJR-08-014, Rev. 0), and the updated Revision 8PTN PRA model (PTN-BFJR-00-001, Rev. 9) provide42 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.P 4eer.tF&O # Description Possible Resolution Plant Response,or Resolution
... ____ _Revieiw
....._" "P""a"i" Resp.nse, series of MAAP 3.Ob analyses wasoerformed for the Turkey Point IPE. The3vailable documentation consists of theAccident Sequence Notebook descriptions 3nd success criteria summary and annternal memo from the IPE, which provides3 summary listing of the MAAP cases thatwere run, along with an indication as toNhether or not core uncovery/vessel failureoccurred.
Reviewer note R11 to table THprovides a comparison of the definitions 3nd their bases, with focus on the injection phase, as discerned from this information:
From the comparison in note R11, it can beseen that the principal difference in sizedefinitions (aside from the names used) is inthe PTN Medium Break category, which isessentially the lower end of the typicalLarge Break category.
Comments on the above are as follows:The available documentation provides theoasis for some, but not all, of the sizeranges noted above. Information providedn FPL memo NF-90-450 (October 19, 1990)provides sufficient information to serve as abasis for the S1 and 52 ranges and the lowerend of the Medium LOCA range. But it doesnot provide any basis for the upper end ofthe Medium LOCA / lower end of the Largetree notebook or appendix, a clear discussion of thebases for the selections, including reference to thespectrum of analysesperformed and the specificset of MAAP or otheranalyses that define thesize range for each sizebreak.Consideration should begiven to evaluating anddocumenting the effect onPRA results and riskinsights resulting fromusing these (as opposed tomore "traditional")
definitions.
Confirm that all definitions are based on analysesperformed usingappropriate codes andmodeling assumptions, especially for the largerbreak size definitions (i.e.,those in the range of 3"and above). Considerconfirming the results ofkey earlier MAAP 3.0bjustification for the LOCA break sizes.43 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.F&. Description
' Pssble Resolution
.Plant Response or Resolution R eview1erltnlPsie[a LOCA size ranges (i.e., the 13.5" break).Available MAAP runs listed in the memo arefor breaks up to 10" diameter.
Discussions with FPL personnel identified that the 13.5"size cutoff may have been selected by theIPE contractor during the early stages of theIPE, but a specific basis was not locatedduring the review.For the TPN Medium LOCA, i.e., breaks upto 13.5 inches, the PRA assumes that asingle train of high head injection canmitigate this class of LOCAs, whereas typicalPRAs would instead tend to credit a singletrain of low head injection for breaks at theupper end of this size range (i.e., above 6").As noted above, analyses supporting theupper end of the Medium LOCA range withthis success criterion were not available during the peer review.MAAP 3.Ob analyses were used to supportthe definition of ECCS requirements for theMLOCA, even at the upper end of the breaksize range (i.e., 13 inches).
In general, MAAP3.Ob is not appropriate for rapiddepressurizations as would be occurring forbreaks in the MLOCA size range.analyses against resultsobtained using currently available versions ofMAAP, which haveimproved capabilities formodeling depressurization and other T/H phenomena.
TH-5WOG2002The Accident Sequence Notebook indicates that core damage is defined, for referenced Revise the discussion ofcore damage conditions
:The new Success Criteria Calculation (PTN-BFJR .1014, Rev. 0) and the updated Revision 8 PTN PRA44 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews."Peer[F&O # :..:.Descrip:ion.
iPosible Resolution Plant Responseor.Resolution F&Ovi .e s w.e.oui.
._ _ _ _ _ _ __ei w ,_ I : :':': ': : , ::::? i
: i _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ I _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _design-basis
: analyses, as 2200 degF peakfuel clad temperature.
No discussion isprovided regarding the core damagecriterion for analyses performed usingMAAP, but it appears, from the available summary of MAAP runs performed for theIPE, that it was assumed that core damagewould occur as soon as core uncovery waspredicted by the code.These definitions are reasonable butconservative (i.e., pessimistic) from a PRAperspective.
The following observations arenoted.The selected core damage criteria can beconsidered to be functions of the accuracyof the code and model being used toand rationale to addressthe capabilities of thecodes and models used.Consider checking to seethat the success criteriawould not changesignificantly if existingconservatisms wereremoved from the model.model (PTN-BFJR-00-001, Rev. 9) define 1% claddamage as the core damage end state.calculate them. For example, supporting requirement SC-A2 of Rev. 14 of the ASMEPRA Standard provides example measures.of core damage that indicate that 2200.degF would be appropriate using a code.With "detailed core modeling" whereas a.lower temperature (e.g., 1800 degF) would:be more appropriate using a code withsimplified (e.g., single node core model,lumped parameter) core modeling".
The:idea is to provide sufficient margin between!actual and code-calculated values to allowIfor limitations in codes and models, and45 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.[Peer I ;____.....
[Reve I Description Resolution
.Plant: Response or Resolution Rev "______ iew ___________________
____________________________________'_
uncertainties in inputs and calculations.
So,for those PRA success criteria for which thelicensing basis analyses provide the successcriteria bases, the 2200 degF value isappropriate.
Where the MAAP code (orother codes / models with more simplified modeling detail than the licensing basiscodes) is used, selection of a lowerpredicted temperature may be moreappropriate.
If core uncovery has been used as the coredamage criterion in the available TurkeyPoint MAAP analyses, it is possible thatsome scenarios for which success credit wasnot taken may in fact be successful.
This isbecause in some events there may be abrief uncovery of the top of the corewithout gross fuel heatup, followed byrefilling of the vessel as injection occurs.Thus, some PRAs apply a combinedtemperature and onset of core uncovery, ortemperature and time, criterion.
It is notpossible to determine from the available MAAP 3b analysis summary which casesmight change, but the breaks in the S2 sizerange represent a set of cases whereadditional investigation might changerequirements.
Other criteria that could beexamined include human action timing.46 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.;F&O # .e Description
.ossible Resolution Plant Response or Resolutin Consideration could also be given todemonstrating the viability of secondary side cooldown and depressurization toallow injection via the RHR or chargingpumps for sequences with failure of thehigh head pumps.It is also important that the events beingmodeled are within the capability of thecode used. In the case of the MAAP code,recent versions (e.g., MAAP 4 and later)have enhanced capabilities relative toMAAP 3b for many events modeled in thePRA.TH-6WOG2002The selection of analytical bases for successcriteria, and the MAAP analyses performed for the IPE are documented only in twointernal memos (FRN-89-1010, November1989, and NF-90-450, October 1990). TheConsider developing aprocess for documenting PRA supporting
: analyses, including guidanceregarding consistent The new Success Criteria Calculation (PTN-BFJR D14, Rev. 0) and the updated Revision 8 PTN PRAmodel (PTN-BFJR-00-001, Rev, 8) resolve this F&O.1989 memo documents results of a reviewof available WCAPs to determine timing andother T/H bases for the IPE, but theconclusions reached there appear to havemainly been superceded by the information in the 1990 memo. The 1990 memoprovides only tabular summary of results ofthe various MAAP cases performed, andprovides no reference for a verified MAAPbase deck, check of input parameters, etc.information (inputs,outputs,dicussion/interpretation ofresults),
and implementing this for future analyses.
Consider having the MAAPanalyst re-document theavailable analysisinformation (per theabove-referenced memos)47 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.F&O # P .Description
... IPossible Resolution.
Plant Response or Resolution Review 7_______________________
The memo also does not provide any in a current calc, addingdiscussion of how the results should be or best-available information were interpreted.
Per discussions with the (e.g., by capturing analystFPL analyst who performed the MAAP recollections) regarding analyses (and who authored the memos), how the results werethere was a preliminary analysis calc interpeted andprepared for the MAAP analyses, but this implemented in the PRA.was not reviewed/approved, since therewere no procedural requirements at thetime to do so. Thus, there is no cleardocumentation of a verified analysis basisfor key PRA success criteria, beyond thesummary information provided in thememos:HR-A2-01FPR 2010This HR requires identification, through areview of procedures and practices, thosecalibration activities that if performed incorrectly can have an adverse impact onthe automatic initiation of standby safetyequipment..
The system notebooks containa detailed listing of testing andmaintenance procedures that wereidentified for each system, but there is nodiscussion as to which procedures weredetermined to have the potential to resultin equipment being left in a miscalibrated condition, and which were screened fromconsideration with the basis for screening.
A review of the procedures listed in the systemnotebooks should beperformed to identifythose that could result inpotential miscalibration events, and provide ajustification for those thatwere excluded fromfurther consideration.
Formiscalibrations that havethe potential to impactmultiple
: systems, ensurethat they are treatedRather than examine all possible maintenance, surveillance, and calibration procedures andassociated practices, a more practical method wasused which presumed that pre-initiators canpotentially exist for all redundant standby trainsmodeled in the PRA and to insert screening values fortheir probability of occurrence.
If quantification of themodel with the screening values demonstrates thatthey are risk significant contributors (FV>0.005),
thena specific review of potential maintenance, surveillance, and calibration procedures and practices that could cause the pre initiator condition to exist isperformed against the screening rules in HR B1. Anyprocedures that meet this criterion are identified and48 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.e .'Possible Resolution Plant Response or Resolution
..& Review Description"
.... Resolution Response orconsistently between both documented in the HRA Calculator file.systems, and that HR-Al presumes that EVERY possible procedure orappropriate HFEs are listed practice that could cause misalignment orin all impacted system miscalibration are identified before any screening ofnotebooks.
events can occur. Further, review of Table 7 revealedthat only 2 of the 9 calibration procedures requiredSimilar traceability needs pre-initiator events for the PRA model, and the eventsto be provided for other were already in the model.Test and Maintenance procedures that have theability to render asystem/equipment unavailable as well.HR-B2-01FPR 2010This SR does not allow screening ofactivities that could simultaneously have animpact on multiple trains of a redundant system or diverse system.Review the actual test andmaintenance procedures associated with thesevalves and determine when they can be subjectto testing or maintenance.
If they can be subject totesting or maintenance when either of the Units isshutdown, then a T&Mneeds to be added into themodel as well asconsideration for a pre-initiator misalignment ofVerify assumption in HHSI system notebook.
If any ofthese valves are rendered unavailable formaintenance during power operation, addappropriate T&M events and pre-initiators.
For the 864 valves, the model has a T&M event foreach RWST to account for the time the RWST contentsare used to fill the refueling canal, which is probablythe only time the 864 valves could be maintained.
TheRWST T&M event should be a palatable substitute.
The 845 and 882 valves are locked-open manualvalves, so no T&M or pre-initiator is needed there.the valves, and a post- The HHSI recirculation valves 856 and 874C, if closed49 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.F&O # Peer '.Description
:Possible Resolution Plant Response or Resolution
,Review :j'initiator HRA to re-align ifnecessary.
For maintenance take out their related HHSI pumps.The 856 valves are stroke-tested during the associated unit refueling outages.
Evaluated pre-initiators for the356 valves and added these to the model.The 878A and 878B valves, if closed for maintenance, Nould prevent opposite-unit SI. Evaluated pre-nitiators for the 878 valves and added these to themodel.rhe 856 valves are stroke-tested during the associated unit refueling outages.
Evaluated pre-initiators for theB56 valves and added these to the model.Ran quantification of the U3 and U4 models withthese pre-initiators added -negligible effect on CDFand LERF.In the latest data update, documented in PTN-BFJR-22-026, Rev. 1, condition reports were reviewed forthe time period 1992-2006 for component failures.
Nofailure modes outside the ones already modeled werefound.The only thing that needs to be fixed for this finding isTable 3 in the 09-12, Rev. 1 calc. The probabilities for4AHFAON2BK1, AHFAON2BK1U4, AHFAON2BK2, and4AHFAON2BK2U4 need to be changed to 4.0E-05,HR-C2-01FPR 2010There is no provided documentation of theplant-specific or applicable genericoperating experience for equipment leftunavailable for response in accidentsequences.
The human failure event probabilities appear to be evaluated with a systematic process that includes an initial screening value and the identification of risk-Provide documentation ofthe review of plant-specific or generic operating experience and confirmthat no additional failuremode is required.
Review and ensureconsistency on thecalculation of HFE for allpre-initiator and post-HR-D-01o FPR 2o01050 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.F&O# Peer ~~*"'SF&O PDescription
" .....:Possible Resolution 1Plant Responrseor Review Dsrpi j.os..ble or Resolution significant action for which a detailed initiator HFEs. matching the probabilities in Table 5 and the PRAanalysis through ASEP method is used. model.Although there appear to be some The probabilities for AHFAON2BKU andinconsistencies in the values of the HEF, AHFAON2BKUU4 need to be changed to 3.6E-05,especially for HEF already existing in matching the probabilities in Table 5 and the PRAprevious version of the model. For example, model.action AHFAON2BK1 is indicated as a pre- The manner in which these pre-initiators areexisting action (i.e., not highlighted in Table calculated is documented in the HRA Calculator file3, page 22) with an initial value of 1.10E-3.
used and referenced in calculation PTN-BFJR-09-011,
:There is no further discussion of this action Rev. 1.(i.e., the action is not indicated in Table 4 at.page 27 as one of the action requiring Only the tables, not the model, need to be changed.:further analysis).
Still in Table 5 at page 31the action has a value of 4.5E-5(consistently with what is in the model).Another example of inconsistency betweenthe documentation, the HRA Calculator fileand the CAFTA model is post-initiator actionAHFPAFWTHROT).
HR-D3-01 I FPR 2010The pre-initiator HRA does not specifically discuss quality of the written procedures orthe quality of the human-machine interface.
To achieve CCII/IlI, adiscussion of the quality ofprocedures and human-machine interface need tobe provided.
For each pre-initiator analyzed in detail in the HRAZalculator, there is an assessment of the quality of theirocedures and human interface in Performance 3haping Factors.HR-G7-01FPR 2010This SR outlines the requirements forassessing the degree of dependence between HEPs contained in a singleReview the cutsetsassociated with Dual-Unit initiating events, and takerhe fatigue rule has forced the site into a 4th RO on;hift. Attachment 1 of the Ops Dept Instruction ODI--0-045, Shift Staffing and Accountabilities, 12/21/0951 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.= == .... .. ...... ..... ..I eer' I ''.F&O # D Description Possible Resolution Plant Response or Resolution accident sequence or cutset, and into consideration the fact has to be filled out by the Field Supervisor for all ofaccounting for the influence of success or that only 1 of the 2 Units the bargaining unit operators to ensure all of thefailure in preceding human actions and will have 2 Reactor required positions are covered.
Note that there is asystem performance on the HEP under Operators available, or that fourth RCO position that they have to fill now. Thatconsideration, including consideration of 1) each Unit may have a should give you what you need to show 2 RCOs pertime required to complete all actions in single dedicated RO, and a unit on shift. The ADMs on the subject have beenrelation to the time available,
: 2) factors that shared RO, and determine changed as well to account for assignment of the 4thcould lead to dependence including the impact of this resource RCO, but they have been carefully worded not tocommon instrumentation, procedures, limitation on the HEP. This contradict Tech Specs which only requires three...even increased stress levels, etc., and 3) review should include ALL though the attached ODI-CO-045 is what they actuallyavailability of resources (e.g. personnel).
dual Unit initiating events use to make sure all of the shift assignments arethat credit any post- covered.initiator
: actions, not onlythose with multiple actionssince the Initiating Eventitself creates thedependency concern.IFPP-B3-01 FPR 2010This SR requires that an uncertainty assessment be included in thedocumentation.
PTN should perform anuncertainty assessment and document theassessment.
The documentation of the internal flooding analysisnow includes a section on uncertainty analysis.
IFQU-A1-01 I FPR 2010This SR states: For each flood scenario, REVIEW the accident sequences for theassociated plant-initiating event group toconfirm applicability of the accidentsequence model. If appropriate accidentsequences do not exist, MODIFY sequences A review of the accidentsequences andquantification resultsshould be documented.
ADD to section 4.2 ...as a result of flooding.
"It shouldbe noted that the accidents sequences defined in theinternal events model were used to quantify internalflooding scenarios.
Each scenario description identifies the existing initiating event to which it is mapped. Nonew sequences or fault tree models were required."
5252 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.' *Peer I)escription 1Poss:b......lu'o...lant F:: R :ecrpto Possible Resolution.
'Plant Response or Resolution as necessary to account for any unique Section 4.2.3.1 specifically discusses main steam andflood-induced scenarios and/or phenomena feed line breaks as being explicitly addressed in thein accordance with the applicable PRA. Add to end of Section 4.2.3.1 -"This scenario isrequirements described in paragraph 4.5.2. not considered further because it is already modeledin the PRA."IFQU-A5-01 I FPR 2010No human failure event discussion ispresented in the analysis.
The documentation ofhuman failure eventsincluded in the analysisshould be provided.
Additionally, the scenariospecific impact on PSFsshould be documented inthe analysis.
The quantification processshould either beNo HFE discussion because no credit was taken for'itigating operator actions.
Added to Section 3.1.2,oaragraph 6 -at specific times are noted. "These timesare noted only to highlight the differences in time)ressures between flood scenarios.
No credit is takenfor operator actions that would mitigate any leak,spray, or rupture.
Subsequently, no human reliability analysis was necessary."
Deleted -"Subsequently, human reliability analysisNas applied in quantifying certain accident scenarios wvhen the early termination of the release is to be-onsidered so as to estimate the probabilities that arelease would not be terminated before certainlamage occurred."
Is for the HFEs from the internal events analysis, thedocumentation of the internal flooding HRA isncluded in the calculation PTN-BFJR-11-010, Rev. 0,which is referenced in the internal flooding analysis-alculation PTN-BFJR-11-009, Rev. 0.The quantification is discussed in Section 4.3 of:alculation PTN-BFJR-11-009, Rev. 0.IFQU-A7-01 I FPR 2010This SR states: PERFORM internal floodsequence quantification in accordance with53 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.LRPeer Rso.t6.Repne RslinF..&.O # veier Description Possible Resoeion Plantesponse or Resolution' the applicable requirements described in documented in theparagraph 4.5.8. flooding
: analysis, or if thesame process has beenused elsewhere, theflooding analysis shouldpoint to that process.Additionally a review of thequantification should bedocumented.
IFSN-All-01 FPR 2010 This SR states: For multi-unit sites with While PTN may not be Dual-unit impacts are discussed where applicable inshared systems or structures, INCLUDE particularly vulnerable to individual flood scenarios.
The effects of these aremulti-unit scenarios, multi-unit
: impacts, such automatically accounted for because the Unit 3 andimpacts need to be Unit 4 models are linked.discussed in thedocumentation.
If thereare no shared systems orstructures, this needs to beexplicitly stated in theanalysis.
IFSN-A16-01 FPR 2010 This SR provides the criteria under which Documentation should be As already mentioned in the response for IFQU-A5, nohuman mitigative actions can be credited.
provided which details the credit is taken for mitigating actions.
The times athuman action being which various equipment fail in each scenario do notcredited, and the basis for imply an end to the scenario.
why they are valid for thescenarios under which theyare credited.
54 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.M6F&O4 Description Possible Resolution
" Plant Response or Resolution
~ ReviewIFSN-A2-01 FPR 2010IFSN-A3-01 I FPR 2010No identification of flood alarms or floordrains has been made in the flood analysisdocument.
This SR states: for each defined flood areaand each flood source, IDENTIFY thoseautomatic or operator responses that havethe ability to terminate or contain the floodpropagation.
No supporting information has beenprovided to justify the estimations regarding flood volumes and thesubsequent flooding height.PTN should document anddlentify the presence offlood alarms and floordrains as related to theirLreatment in the analysis.
PTN should identifyresponses which have theability to terminate or-ontain flood propagation, and provide a justification for the timing used in theanalysisPTN should document thezalculations performed indetermining flood volumesn a given flood area as itrelates to equipment in theroom (the floor area theaquipment takes up), the-apacity of the system, theength of time the floodoersists, etc.See response for IFQU-A5 -No credit taken foroperator action to mitigate flood; therefore, therewas no need to credit flood alarms.Add to end of Section 3.1.3 -"In looking at floodpropagation by backflow through shared drain lines,no credit was taken for check valves."Drain lines were not credited in determining theimpact of a flood in a particular room.As already mentioned in the response for IFQU-A5-01, no credit is taken for mitigative actions.The flooding calculations were added to the notebookalong with added discussion in Section 3.2.I FSN-A4-01 FPR 201055 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.POeer .F&O # R Description
, , Possible Resolutions
: Plant Response or Resolution IFSN-A6-01 FPR 2010 This SR States: For the SSCs identified in IF- Analysis should be Added to section 3.1.2, paragraph 5 end -"In light ofC2c, IDENTIFY the susceptibility of each SSC performed which includes this, it should be noted that only spray andin a flood area to flood-induced failure failure by submergence or submergence damage were included in the scope ofmechanisms.
spray, and a qualitative this evaluation."
INCLUDE failure by submergence and spray assessment of other failurein the identification process.
mechanisms needs to beEITHER: provided (e.g. jeta) ASSESS qualitatively the impact of flood- impingement, pipe whip,induced mechanisms that are not formally
: humidity, condensation, addressed (e.g., using the mechanisms temperature
: concerns, andlisted under Capability Category III of this any other identified failurerequirement),
by using conservative modes in the identification assumptions; OR process.)
Note that theb) NOTE that these mechanisms are not qualitative assessment is aincluded in the scope of the evaluation, requirement of the NRCNo discussion has been provided for the Clarification of this SR.impact due to the additional flood failuremechanisms.
IFSN-A8-01 I FPR 2010This SR states: IDENTIFY inter-area propagation through the normal flow pathfrom one area to another via drain lines;and areas connected via back flow throughdrain lines involving failed check valves,pipe and cable penetrations (including cabletrays), doors, stairwells, hatchways, andHVAC ducts. INCLUDE potential forstructural failure (e.g., of doors or walls)due to flooding loads.Documentation of lessobvious possiblepropagation pathwaysneeds to be addressed.
Appendix B includes this info already.
Added toSection 3.1.3 -"These pathways are listed in AppendixB under the 'Drainage' section of each zone."5656 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.Peer A, or lseoutonn
&O# #la Description Possible Resolution Pint Response or.Resolution" iReview .: :i ...:: :,:IFSO-A1-01 FPR 2010 Based on a confirmatory walkdown It is recommended that the The chilled water system operates at very lowperformed the Peer Review Team, the analyst ensures that spacial pressure and the lines are insulated, precluding thelocations/impacts of some pipes containing information be captured possibility of a spray. This information was added towater may have been overlooked in the appropriately for spray the scenario description.
analysis.
concerns.
Equipment hasbeen identified inwalkdown sheets forelevation, but not spatiallocation.
Additionally theanalyst should ensure thatall potential fluid sources ina given flood area areidentified, and allpotentially impactedequipment is identified theimpact of it failing isevaluated.
IFSO-A3-01 FPR 2010 No process by which screening was PTN should document As mentioned in IFPP-B1, no screening wasperformed is present in the analysis.
justification for screening performed, all areas were considered.
particular flood areas fromfurther analysis.
IFSO-A4-01 I FPR 2010No human-induced mechanisms have beenincluded in the analysis, and additionally, noprocess which justifies their exclusion wasprovided.
It is identified that tankDverfills will relief to vents,drains or the wastedisposal system but it isrecommended that specificnstances be discussed as it,s mentioned in Section 3.1.2, human-induced mechanisms are already taken into account in thegeneral failure data.57 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.F&O # eR 1 Descito 'PossibleReslutio Pln Resonse or Resolution Review. cito suinsrelates specifically tooperator induced failures.
Additionally, a process orprogram should beidentified which preventshuman-induced floodsfrom occur, thereby*ustifying their exclusion from the analysis.
IFSO-A5-01 FPR 2010 No summary or characterization of flood Characterize flood sources The flooding calculations were added to the notebooksources included in the analysis has been in terms of capacity, flow along with added discussion in Section 3.2.provided.
It is difficult to tell what the rate, pressure, decisions making up the source temperature, etc.characterization were. Additionally, document theustification for a givenflow rate. PTN should alsodocument the processused to identify potential flood sources.DA-D5-01 FPR 2013 For several CCF groups, a "global common Two alternatives.
The Could not find guidance regarding adding ct5 to c6 tocause event" (as described at the end of missing CCF terms could be approximate the 5/6 combinations in INEL-94/0064, Section 4.2 of PTN-BFJR-2008-012, Rev. 0) is added to the CAFTA fault but it makes sense. Does the reviewer have a specificused. While this is a reasonable trees and CCF basic events reference (document and page number) for this?simplification, the global common cause calculated for the newevent needs to account for the common terms. A simplercause combinations that are not included alternative is to revise the:explicitly.
: However, for several 6- calculation of the a6 term58 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.F&O# DPeer scription jPossible Resolution Plant Resiponse or-Resolution
: Review De rito : : ..t~~~I:i !: ...DA-D6-01component groups (AFW AOVs FTO, AFWCVs FTO, AFW MOVs FTO), the 5-of-6 terrwas not included and the 6-of-6 term wasnot adjusted.
A similar issue appears to bepresent for SG SVs FTO (4-component group), where only the 4-of-4 term isincluded (the 2-of-4 and 3-of-4 terms aremissing and the 4-of-4 term was notadjusted).
.. ... ...,. :::: .:: .................
: :......................
..=. = =. ...... ................ ....... .... ............. ..... ........The CCF notebook did not include a revievof plant failure data for common causeevents..2 3..........
M.1FPR 2013to include the missing a5value. Thus, ax6' = a5 + a6.This overestimates the a5contribution, since it isapplied to the case whereall 6 components fail, butthis should be a small andconservative approximation.
(Similarcorrection for the 4-component group, a4' a c2+ 03 + a4).vReview plant-specific component failure eventsfrom the most recent dataupdate to identify anycommon cause failures.
IfCCFs are identified, verifythat the CCF is modeled forthe specific component and failure mode. if thisdata indicates asignificantly larger fractionof failures are CCFs thanthe generic CCFparameters would predict,plant-specific CCFparamneters should be-:::1 ... ...........
..--..,...... .. ......: : ! ::! :!! : ..... ...... .. .. .........
.1 .;; .==:::: :.,...,,:...-4:::
...........
I ....... ........
.............
I ..; ::.!!.This needs to be done to meet the Standard, but Idon't expect to find any plant-specific CCFs.59 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.: # .e Description,"
I Possible Resolution plant Response orResolution'
.F&O #. Review D, ,s, ." , .' ..l R o ui. n or_ .__;, _ __._..._
_ _ __._.., .__ _ _ _ _ _ _ _ ....'..* .. ....., ..'.calculated.
If the data islimited (one or two failuresin a specific component group), this would not besufficient evidence toJustify plant-specific CCFparameters.
DA-D6-02 FPR 2013 Section 3.0 of the CCF Notebook includes Provide a basis for CCFs are included for the components in the initiating the assumption that CCFs are not included excluding CCFs from event fault trees. For example, in the CCW systemin fault tree initiating events with year-long system initiating events where 2/3 pumps are normally
: running, there aremission times due to excessive and include CCFs where a AND gates with a single FTR event of one of theconservatism in applying CCF factors that basis for exclusion cannot normally running pumps with an 8760-hour missionare developed for 24-hr mission time. be established.
For time and CCF events for the other 2 running pumpsHowever, this is not sufficient basis for example, include CCF in with mission times equal to the MTR of the pumps.e.xcluding CCFs for fault tree IE models. system initiating event There is not a CCF for all 3 pumps with a mission timemodels only for active of 8760 hours, nor should there be; all 3 pumps arecomponents that are in the not normally running at the same time, and certainly same configuration (i.e., not for 8760 hours.between normallyoperating pumps in thesame system but notbetween operating andstandby pumps in the samesystem).IE-C14-01 FPR 2013 *{RCP TBHX rupture probability
-The IE Assess the tube rupture Will assess..frequency for tube rupture is based on a original source data and....... ..Reference 5 value of 3.48E-08/hr (peer whether it is applicable to60 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews....e. Decrpto .Possible Resolution Plant Response or Resolution review did not verify this reference) for "HX each thermal barrierTube External Leak Large >50 gpm". This cooler/RCP.
Revise initiator hourly frequency is multiplied by 8760hr/yr
%ZZISLTBCCW andfor an annual IE frequency of 3.05E-04/yr.
document any changes orDepending on the application of the data, basis accordingly.
this IE frequency could be applied at eachRCP, thus event tree top event "RCP TBHXTubes Intact?"
would be multiplied by afactor of 3. Applicability of the TBHX datato one or all RCPs should beexamined/documented for impact on thetotal %ZZISLTBCCW initiator/results.
IE-C14-02 FPR 2013 Manual operator action is credited for local Evaluate and document The fact that the pressure increase in the CCW systemmanual closure of MOV-*-626 (should it fail whether the operator due to the TBHX tube rupture would be mitigated by*to close) and/or to local closure of manual action should be credited the CCW surge tank expansion volume and the reliefvalve *-736. Operator success ensures that and remove credit for the valve RV-3/4-707 opening at 50 pisg are obviously thethe CCW piping remains intact. Although action if it cannot be reason some credit is given to closing a valve to isolatethe HEP for the local action is 0.5, the time ustified the leak. The time available for performing thewindow basis should document to ensure isolation will depend upon the size of the rupture as*that the operator has sufficient time to well as other factors.
Need to find Westinghouse perform these actions before the CCW letter FPL 88-757. Since the HEP is already high at 0.5,piping boundary fails. this may be more trouble than it's worth.IE-C14-03 FPR 2013 Thermal Barrier ISLOCA IE Frequency
-RCP Evaluate and document the Will examine these penetrations for ISLOCA potential.
Thermal Barrier CCW Supply Penetration
#3 TBCCW supply penetration
-This penetration is not evaluated for for possible ISLOCApotential ISLOCA contribution.
This initiating events. Should.... ........
._._ penetration is protected by two normally also assess the impact on61 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.F&O # Ri Possi blee Resolution Plant.Response or Resolution Review Description or Re ie 4 :: .. ..; ; .......open, active check valves (717 and CCW return line from RCP721A/B/C) inside containment and two motor cooling and lifting of:normally open MOVs (716A/B) outside RV-729 if V-712A failscontainment.
The associated piping inside open. Ensure that thesecontainment appears to be designed for full penetrations are, alsoRCS pressure.
: However, given a thermal identified in Table 1, list ofbarrier tube breach, the active check valves penetrations.
could fail to close (w/CCF).
The active failureof the outboard MOVs (also w/CCF) may behighly unreliable due to low differential pressure design capability and lack ofrelevant closure signals, and there mightnot be sufficient time for manual action.Failure of this penetration should beassessed for possible contribution to theTBCCW ISLOCA event frequency andsequences.
......... ... ......... .... ..... .... .. .. ......... ...... .... ., .... .... ... .. .. ................IE-C14-04 I FPR 2013ISLOCA assessment of Penetration 1 (RHRSDC suction line) did not consider that thecommon suction piping beyond the RHRpumps could be affected by the over-pressurization event. This would impact thefunction of the high head SI pumps and theRWST (and Containment Spray pumps,which are not important in ISLOCAscenarios).
As a result, the current RHRsmall ISLOCA event sequences apply toomuch credit for the associated Unit's RWSTEvaluate and document theRHR small ISLOCAsequences taking no creditfor associated Unit HHSIpumps and RWST.Good catch. Will be making this change.62 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.Ir Descrition Possible Resolution
.Plant Res or-Resolution and HHSI pumps.IE-C14-05 FPR 2013 Penetrations 58/59/60:
(HHSI cold leg Review these penetrations I assume the issue here is that 3 closed check valves'injection)
-These penetrations are and provide further basis are not believed to be equivalent to 3 manuallyqualitatively screened from further detailed for screening.
isolated manual valves. Still, the probability of 3.evaluation on the basis that ....' the closed check valves opening against pressure is likelyCombination of three check valves is to be adequately low for screening.
equivalent to three locked/closed isolation valves",
for meeting NUREG/CR-5928 criterion (c), systems isolated by redundant
.normally closed and locked manual valvesthat are independently verified to be closedand locked before plant startup".
Thiscomment is also applicable to Penetration
: 18. Additional basis is needed to supportthis equivalency assertion for screening these penetrations.
IE-C14-06 FPR 2013Suggestion.
The PTN ISLOCA analysis isbased on earlyNUREG information and industry
: practice, which continue to provide a reasonable source of inputs/practice for consideration in ISLOCA modeling.
In general however,the evaluation might benefit from aspectsDf the latest industry ISLOCA bestpractice/methodology presented in WCAP-17154, Rev.l.Consider updating theISLOCA evaluation tocurrent industry practiceand reference material.
Itis noted that there arelimitations in the WCAP-17154, Revision 1methodology and itscomplete adoption is notrecommended.
Will likely update the ISLOCA model with the benefitof the latest guidance when resources permit.63 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.F #Description 0 os ibil e'Resolutlatioposeo Resolution~
Review" :P e " ... :::.:.. i! : ''":" ' ... =::* ' " ;'. ..: : .:.....:!.
...::' .IE-C14-07 FPR 2013 !Suggestion.
Table 1 "Potential ISLOCA Flow Paths" -Consider adding more detail in the ISLScreening Results column. For example,Penetrations 13 and 14 (Letdown andCharging) may not cleanly screen. Bothsystems interface with low pressuresystems (letdown-purification piping andcharging-pump suction).
Typically there areredundant isolation means to isolate -thusIE frequency should be low. However, thiscannot be concluded from the table details.Also, Penetration 3, "RCP CCW Supply"indicates that this penetration wasscreened based on "not connected to theRCS". However, this penetration providesthe CCW supply to RCP thermal barriercooling and should be assessed (refer toF&O IE-C14-2).
Electrical penetration assembly failuremodes have been found to be important contributors to overall containment fragility at other large dry PWRs, and in at least 2instances, tend to be the most limiting interms of ultimate failure pressure.
Additionally, early studies at SandiaNational Laboratories have considered thepotential impact of very high (beyondConsider updating theISLOCA report to improvethe details in Table 1,primarily the columninformation under "ISLScreening Results"Perform a scopingassessment of thepotential impact ofelectrical penetration thermal-mechanical DK.LE -D2 -0 1 FPR 2013For containment isolation, the Level 2 updateincorporated the existing containment isolation analysis; it did not revisit this issue directly.
As forcontainment
: strength, this was also something thatwas provided and was not re-investigated, so wouldnot have affected the analysis directly.
The place inthe Level 2 model where this would have an effectwould be the "Containment Failure at Vessel Breach"events, which were determined via NUREG sources toresponse to severeaccidents.
Consider usingsome of the following references:
NUREG/CR-64 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.RF&O # Reew Descrijption
' " PosibleRsolution
.Plant Response or Resolution design basis) temperatures on elastomer seals (this latter issue is more critical forsmall volume containments such as BWRMark I).4944, CR-5083, CR-5096,CR-5118, and CR-5334.be minimal.
It is not known whether these referenced NUREGs already factored such considerations intotheir containment strength estimates and failureprobabilities, but it is not expected to have asignificant effect.LE-F1-01LE-G5-01FPR 2013Endstate frequency totals are given in Table5 of the Level 2 notebook, PTN-BJFR )10, Rev. 1, and results by release categoryare given in Table 6. However, results usingthe Plant Damage State definitions ofSection 4.2 are not provided.
CC II is notmet because relative contribution to LERFby PDS is not shown, although information is available to provide such data.Perform summarycalculation to quantify PDSrelative contribution toLERF.Will add to update calculations.
.. .........
.... ... ....... ... ..........
... ...... ..... .. ............
... .. .. .. ..... ................
... ................
... .... .. ............
............
....FPR 2013There is no discussion of limitations ofsevere accident understanding andmodeling.
This includes such matters as theimpact of uncertainty regarding thermally induced SGTR on quantification, theuncertainty of ISLOCA break size andlocation on timing and source term, and theassignment of CET to endstates.
Conservative treatment of somephenomena can affect LERF quantification, vhich in turn impacts LERF and delta LERFresults when applying RG 1.174 guidelines n risk-informed changes to the licensing Provide a discussion ofpossible limitations of theLERF analysis based on, forexample, limitations on thestate of severe accidentunderstanding and level 2PRA analysis.
Brieflydescribe how keyuncertainties in the LERFquantification could impactrisk-informed changes tothe licensing basis underRG 1.174, for example.Will add discussion.
65 Enclosure
-Peer Review FindingsThis table summarizes facts and observations with significance ranking "A" or "B" from the 2002 global peer review and the findings from the 2010 and 2013focused peer reviews.isis, for example.66 Turkey Point Units 3 and 4Docket Nos. 50-250 and 50-251L-2014-033 Attachment 3Attachment 3Turkey Point Nuclear PlantLicense Amendment Request No. LAR-229Technical Specifications Marked-Up PagesThis coversheet plus 105 pages.
Turkey Point Units 3 and 4Docket Nos. 50-250 and 50-251L-2014-033 Attachment 3Turkey Point Nuclear PlantUnits 3 and 4Technical Specifications Marked-Up PagesList of Affected Pages3/4 1-1 3/4 2-6 3/4 3-34 3/4 4-20 3/4 6-7 3/4 7-12 3/4 8-233/41-2 3/42-7 3/43-38 3/44-25 3/46-11 3/47-13 3/49-13/4 1-4 3/4 2-8 3/4 3-39 3/4 4-28 3/4 6-12 3/4 7-14 3/4 9-23/4 1-8 3/42-12 3/4 3-40 3/44-37 3/46-13 3/47-15 3/49-83/4 1-10 3/4 2-15 3/4 3-46 3/4 4-39 3/4 6-14 3/4 7-16b 3/4 9-93/41-12 3/42-16 3/43-49 3/45-1 3/46-15 3/47-17 3/4 9-123/4 1-15 3/43-8 3/44-1 3/45-2 3/46-18 3/47-22 3/49-153/41-18 3/43-9 3/44-2 3/45-5 3/47-3 3/4 8-4a 3/410-33/4 1-21 3/4 3-10 3/4 4-4 3/4 5-7 3/4 7-4 3/4 8-5 6-18c3/4 1-22 3/4 3-31a 3/4 4-5 3/4 5-8 3/4 7-7 3/4 8-63/4 1-23 3/4 3-32 3/4 4-6 3/4 5-10 3/4 7-9 3/4 8-93/4 1-24 3/4 3-32a 3/4 4-9 3/4 6-1 3/4 7-11 3/4 8-143/4 1-26 3/4 3-33 3/4 4-10a 3/4 6-5 3/4 7-11 a 3/4 8-153/4 2-2 3/4 3-33a 3/4 4-18 3/4 6-6 3/4 7-1 lb 3/4 8-20List of Pages for Information Only3/4 3-1 3/4 3-47 3/4 8-73/43-13 3/44-23 3/48-83/4 3-35 3/4 4-263/4 3-41 3/4 7-8 Turkey Point Units 3 and 4 L-2014-033 Docket Nos. 50-250 and 50-251 Attachment 3Insert INote that Insert 1 capitalization and punctuation is varied based on the use in each specificsurveillance requirement.
In accordance with the Surveillance Frequency Control Program.Insert 21. Surveillance Frequency Control ProgramThis program provides controls for Surveillance Frequencies.
The program shall ensurethat Surveillance Requirements specified in the Technical Specifications are performed at intervals sufficient to assure the associated Limiting Conditions for Operations aremet:a. The Surveillance Frequency Control Program shall contain a list of frequencies ofthose Surveillance Requirements for which the frequency is controlled by theprogram.b. Changes to the frequencies listed in the Surveillance Frequency Control Programshall be made in accordance with NEI 04-10, "Risk-Informed Method for Controlof Surveillance Frequencies,"
Revision 1.c. The provisions of Surveillance Requirements 4.0.2 and 4.0.3 are applicable tothe frequencies established in the Surveillance Frequency Control Program.
3/4.1 REACTIVITY CONTROL SYSTEMS3/4.1.1 BORATION CONTROLSHUTDOWN MARGIN -Ta,9 GREATER THAN 200°FLIMITING CONDITION FOR OPERATION 3.1.1.1 The SHUTDOWN MARGIN shall be within the limits specified in the COLR.APPLICABILITY:
MODES 1, 2*, 3, and 4.ACTION:With the SHUTDOWN MARGIN not within limits, immediately initiate and continue boration at greater than orequal to 16 gpm of a solution containing greater than or equal to 3.0 wt% (5245 ppm) boron or equivalent until therequired SHUTDOWN MARGIN is restored.
SURVEILLANCE REQUIREMENTS 4.1.1.1.1 The SHUTDOWN MARGIN shall be determined to be within the limits specified in the COLR:a. Within 1 hour after detection of an inoperable control rod(s) and at least once per 12 hoursthereafter while the rod(s) is inoperable.
If the inoperable control rod is immovable oruntrippable, the above required SHUTDOWN MARGIN shall be verified acceptable with anincreased allowance for the withdrawn worth of the immovable or untrippable control rod(s);b. When in MODE 1 or MODE 2 with Ke, greater than or equal to 1 at least cncc per 12 hc.rs byverifying that control bank withdrawal is within the limits of Specification 3.1.3.6;c. When in MODE 2 with Ke, less than 1, within 4 hours prior to achieving reactor criticality byverifying that the predicted critical control rod position is within the limits of Specification 3.1.3.d. Prior to initial operation above 5% RATED THERMAL POWER after each fuel loading, byconsideration of the factors of Specification 4.1.1.1 .le. below, with the control banks at themaximum insertion limit of Specification 3.1.3.6; and*See Special Test Exceptions Specification 3.10.1. Insert 1TURKEY POINT -UNITS 3 & 43/4 1-1AMENDMENT NOS. 24:F AND 24 In accoSurveilFrequePrograREACTIVITY CONTROL SYSTEMSSURVEILLANCE REQUIREMENTS (Continued)
: e. W he in M O D E 3 or 4, at least r, n , pe r 24 ..... by consideration of the follow ing factors:1) Reactor Coolant System boron concentration, 3rdance with thelance 2) Control rod position,
.rcy Controlm, when 3) Reactor Coolant System average temperature, Insert 14) Fuel burnup based on gross thermal energy generation,
: 5) Xenon concentration, and6) Samarium concentration.
4.1.1.1.2 When in Mode 1 or 2, the overall core reactivity balance shall be com ped to predicted values todemonstrate agreement within +/- 1% Ak/k at-least o per 31 Effectiv Full ,ower Days (EFPr D). Thiscomparison shall consider at least those factors stated in Specification 4.1.1.1.1e, above. The predicted reactivity values shall be adjusted (normalized) to correspond to the actual core conditions prior to exceeding a fuel burnupof 60 EFPD after each fuel loading.TURKEY POINT -UNITS 3 & 43/41!-2AMENDMENT NOS. "-7-AND +
REACTIVITY CONTROL SYSTEMSSHUTDOWN MARGIN -Taog LESS THAN OR EQUAL TO 200°FLIMITING CONDITION FOR OPERATION 3.1.1.2 The SHUTDOWN MARGIN shall be within the limit specified in the COLR.APPLICABILITY:
MODE 5.ACTION:With the SHUTDOWN MARGIN not within limits, immediately initiate and continue boration at greater than orequal to 16 gpm of a solution containing greater than or equal to 3.0 wt% (5245 ppm) boron or equivalent until therequired SHUTDOWN MARGIN is restored.
SURVEILLANCE REQUIREMENTS 4.1.1.2 The SHUTDOWN MARGIN shall be determined to be within the limit specified in the COLR:a. Within 1 hour after detection of an inoperable control rod(s) and at least once per 12 hoursthereafter while the rod(s) is inoperable.
If the inoperable control rod is immovable oruntrippable, the SHUTDOWN MARGIN shall be verified acceptable with an increased allowance for the withdrawn worth of the immovable or untrippable control rod(s); andb. At lea s'.. pcr 24 huFr by consideration of the following factors:1) Reactor Coolant System boron concentration,
ýInsert 1 2) Control rod position,
: 3) Reactor Coolant System average temperature,
: 4) Fuel burnup based on gross thermal energy generation,
: 5) Xenon concentration, and6) Samarium concentration.
TURKEY POINT -UNITS 3 & 43/4 1-4AMENDMENT NOS. -24 AND 24-+
REACTIVITY CONTROL SYSTEMS3/4.1.2 BORATION SYSTEMSFLOW PATH -SHUTDOWNLIMITING CONDITION FOR OPERATION 3.1.2.1 As a minimum, one of the following boron injection flow paths shall be OPERABLE and capable of beingpowered from an OPERABLE emergency power source:a. A flow path from the boric acid storage tanks via a boric acid transfer pump and a chargingpump to the Reactor Coolant System if the boric acid storage tank in Specification 3.1.2.4a.
isOPERABLE, orb. The flow path from the refueling water storage tank via a charging pump to the Reactor CoolantSystem if the refueling water storage tank in Specification 3.1.2.4b.
is OPERABLE.
APPLICABILITY:
MODES 5 and 6.ACTION:With none of the above flow paths OPERABLE or capable of being powered from an OPERABLE emergency power source, suspend all operations involving CORE ALTERATIONS or positive reactivity changes.SURVEILLANCE REQUIREMENTS 4.1.2.1 At least one of the above required flow paths shall be demonstrated OPERABLE:
: a. At least once per 7 days by verifying that the temperature of the rooms containing flow pathcomponents is greater than or equal to 62&deg;F when a flow path from the boric acid tanks is used,$<[Insert 1 andb. t least onee pe 31 days by verifying that each valve (manual, power-operated, or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correctposition.
TURKEY POINT -UNITS 3 & 43/4 1-8AMENDMENT NOS. ,49-AND 245 REACTIVITY CONTROL SYSTEMSSURVEI LLANCE REQUIREMENTS 4.1.2.2 The above required flow paths shall be demonstrated OPERABLE:
: a. At least once per 7 days by verifying that the temperature of the rooms containing flow pathrt 1 components is greater than or equal to 620F when a flow path from the boric acid tanks is used;b. by verifying that each valve (manual, power-operated, or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correctposition;
: c. At Icast once pcr 18 ,mcnth by verifying that the flow path required by Specification 3.1.2.2a.
and c. delivers at least 16 gpm to the RCS.TURKEY POINT -UNITS 3 & 43/4 1-10AMENDMENT NOS. 249-AND245-REACTIVITY CONTROL SYSTEMSBORATED WATER SOURCE -SHUTDOWNLIMITING CONDITION FOR OPERATION 3.1.2.4 As a minimum, one of the following borated water sources shall be OPERABLE:
: a. A Boric Acid Storage System with:1) A minimum indicated borated water volume of 2,900 gallons per unit,2) A boron concentration between 3.0 wt% (5245 ppm) and 4.0 wt.% (6993 ppm), and3) A minimum boric acid tanks room temperature of 620F.b. The refueling water storage tank (RWST) with:1) A minimum indicated borated water volume of 20,000 gallons,2) A boron concentration between 2400 ppm and 2600 ppm, and3) A minimum solution temperature of 390F.APPLICABILITY:
MODES 5 and 6.ACTION:With no borated water source OPERABLE, suspend all operations involving CORE ALTERATIONS or positivereactivity changes.SURVEI LLANCE REQUIREMENTS 4.1.2.4 The above required borated water source shall be demonstrated OPERABLE:
: a. At least u. ce pef 7 days by:1) Verifying the boron concentration of the water,Insert 1 2) Verifying the indicated borated water volume, and3) Verifying that the temperature of the boric acid tanks room is greater than or equal to620F, when it is the source of borated water.TURKEY POINT -UNITS 3 & 43/4 1-12AMENDMENT NOS. 249-AND 2 REACTIVITY CONTROL SYSTEMSSURVEILLANCE REQUIREMENTS 4.1.2.5 Each borated water source shall be demonstrated OPERABLE:
: a. .t 8aGct cncz par 7 days by:1 Verifying the boron concentration in the water,Insert 1 2) Verifying the indicated borated water volume of the water source, and3) Verifying that the temperature of the boric acid tanks room is greater than or equal to620F, when it is the source of borated water.b. By verifying the RWST temperature is within limits whenever the outside air temperature is lessthan 390F or greater than 1 00&deg;F at the following frequencies:
: 1) Within one hour upon the outside temperature exceeding its limit for 23 consecutive hours, and2) At least once per 24 hours while the outside temperature exceeds its limits.TURKEY POINT -UNITS 3 & 43/4 1-15AMENDMENT NOS. 24-9 AND 24-a REACTIVITY CONTROL SYSTEMSLIMITING CONDITION FOR OPERATION (Continued)
: d. With one full length rod inoperable due to causes other than addressed by ACTION a, above,or misaligned from its group step counter demand position by more than the Allowed RodMisalignment of Specification 3.1.3.1, POWER OPERATION may continue provided that withinone hour either:1. The rod is restored to OPERABLE status within the Allowed Rod Misalignment ofSpecification 3.1.3.1, or2. The remainder of the rods in the bank with the inoperable rod are aligned to within theAllowed Rod Misalignment of Specification 3.1.3.1 of the inoperable rod while maintaining the rod sequence and insertion limits of Specification 3.1.3.6; the THERMAL POWERlevel shall be restricted pursuant to Specification 3.1.3.6 during subsequent operation, or3. The rod is declared inoperable and the SHUTDOWN MARGIN requirement ofSpecification 3.1.1.1 is satisfied.
POWER OPERATION may then continue provided that:a) The THERMAL POWER level is reduced to less than or equal to 75% of RATEDTHERMAL POWER within one hour and within the next 4 hours the power rangeneutron flux high trip setpoint is reduced to less than or equal to 85% of RATEDTHERMAL POWER. THERMAL POWER shall be maintained less than or equalto 75% of RATED THERMAL POWER until compliance with ACTIONS3.1.3.1.d.3.c and 3.1.3.1.d.3.d below are demonstrated, andb) The SHUTDOWN MARGIN requirement of Specification 3.1.1.1 is determined atleast once per 12 hours, andc) A power distribution map is obtained from the movable incore detectors andF0 (Z) and FNAH are verified to be within their limits within 72 hours, andd) A reevaluation of each accident analysis of Table 3.1-1 is performed within 5days; this reevaluation shall confirm that the previously analyzed results of theseaccidents remain valid for the duration of operation under these conditions.
SURVEILLANCE REQUIREMENTS 4.1.3.1.1 The position of each full length rod shall be determined to be within the Allowed Rod Misalignment of ..1the group step counter demand position at lept encc pcr 12 hours (allowing for one hour thermal soak after rodmotion) except during time intervals when Rod Position Deviation Monitor is inoperable, then verify the grouppositions at least once per 4 hours.4.1.3.1.2 Each full length rod no Ily inserted in the core shall be determined to be OPERABLE by movement ofat least 10 steps in any one di ction at leact onco por 92 day,.TURKEY POINT -UNITS 3 & 43/4 1-18AMENDMENT NOS. ,38 AND 2 REACTIVITY CONTROL SYSTEMSSURVEILLANCE REQUIREMENTS 4.1.3.2.1 Each analog rod position indicator shall be determined to be OPERABLE by verifying that the DemandPosition Indication System and the Analog Rod Position Indication System agree within the Allowed RodMisalignment of Specification 3.1.3.1 (allowing for one hour thermal soak after rod motion) at ec.- nc F 12except during time intervals when the Rod Position Deviation Monitor is inoperable, then co pare theDemand Position Indication System and the Analog Rod Position Indication System at least once r 4 hours.4.1.3.2.2 Each of the above required analog rod position indicator(s) shall be determined to be OP RABLEby performance of a CHANNEL CHECK, CHANNEL CALIBRATION and ANALOG CHANNEL OP TIONALTEST performed in accordance with Table 4.1-1.Ilnsert 1TURKEY POINT -UNITS 3 & 43/4 1-21AMENDMENT NOS. 2 AND-&
Replace each marked throughSurveillance Frequency with "SFCP".TABLE 4.1-1ROD POSITION INDICATOR SURVEILLANCE REQUIREMENTS Functional UnitIndividual Rod PositionDemand PositionCheck-S---Calibration
.-4R-Operational Test----R--N/ATURKEY POINT -UNITS 3 & 43/4 1-22AMENDMENT NOS. t4-AND 4-32 REACTIVITY CONTROL SYSTEMSPOSITION INDICATION SYSTEM -SHUTDOWNLIMITING CONDITION FOR OPERATION 3.1.3.3 The group step counter demand position indicator shall be OPERABLE and capable of determining within+/- 2 steps the demand position for each shutdown and control rod not fully inserted.
APPLICABILITY:
MODES 3* **, 4* **, and 5* **ACTION:With less than the above required group step counter demand position indicator(s)
: OPERABLE, open the reactortrip system breakers.
SURVEILLANCE REQUIREMENTS 4.1.3.3.1 Each of the above required group step counter demand position indicator(s) shall be determined to beOPERABLE by movement of the associated control rod at least 10 steps in any one direction p 31-4ays. lInsert 14.1.3.3.2 OPERABILITY of the group step counter demand position indicator shall be verified in accordance with--LTable 4.1-1.* With the Reactor Trip System breakers in the closed position.
** See Special Test Exceptions Specification 3.10.5."X-TURKEY POINT -UNITS 3 & 43/4 1-23AMENDMENT NOS. 4-49 AND 444-REACTIVITY CONTROL SYSTEMSROD DROP TIMELIMITING CONDITION FOR OPERATION 3.1.3.4 The individual full-length (shutdown and control) rod drop time from the fully withdrawn position shall beless than or equal to 2.4 seconds from beginning of decay of stationary gripper coil voltage to dashpot entry with:a. Tavg greater than or equal to 5000F, andb. All reactor coolant pumps operating.
APPLICABILITY:
MODES 1 and 2.ACTION:With the drop time of any full-length rod determined to exceed the above limit, restore the rod drop time to withinthe above limit prior to proceeding to MODE 1 or 2.SURVEILLANCE REQUIREMENTS 4.1.3.4 The rod drop time of full-length rods shall be demonstrated through measurement prior to reactorcriticality:
: a. For all rods following each removal of the reactor vessel head,b. For specifically affected individual rods following any maintenance on or modification to theControl Rod Drive System which could affect the drop time of those specific rods, andC. At easten-eieepeF 18 -ie i s.linsertTURKEY POINT -UNITS 3 & 43/41!-24AMENDMENT NOS. 244-AND 2f8-REACTIVITY CONTROL SYSTEMSCONTROL ROD INSERTION LIMITSLIMITING CONDITION FOR OPERATION 3.1.3.6 The control banks shall be limited in physical insertion specified in the Rod Bank Insertion Limits curve,defined in the CORE OPERATING LIMITS REPORT.APPLICABILITY:
MODES 1* and 2***ACTION:With the control banks inserted beyond the above insertion limits, except for surveillance testing pursuant toSpecification 4.1.3.1.2 either:a. Restore the control banks to within the limits within 2 hours, orb. Reduce THERMAL POWER within two hours to less than or equal to that fraction of RATEDTHERMAL POWER which is allowed by the bank position specified in the Rod Bank Insertion Limits curve, defined in the CORE OPERATING LIMITS REPORT, orc. Be in at least HOT STANDBY within 6 hours.SURVEILLANCE REQUIREMENTS 4.1.3.6 The position of each control bank shall be determined to be within the insertion limits--hours, except during time intervals when the Rod Insertion Limit Monitor is inoperable, then vrod positions at least once per 4 hours.individual
* See Special Test Exceptions Specifications 3.10.2 and 3.10.3.** With Ke, greater than or equal to 1.0TURKEY POINT -UNITS 3 & 43/4 !-26AMENDMENT NOS. 2-3&AND 23-POWER DISTRIBUTION LIMITSSURVEILLANCE REQUIREMENTS 4.2.1.1 The indicated AFD shall be determined to be within its limits during POWER OPERATION above 50% ofiKRATED THERMAL POWER by: +a. Monitoring the indicated AFD for each OPERABLE excore channel:1) ' once per. days when the alarm used to monitor the AFD is OPERABLE, and'2) At least once per hour for the first 6 hours after restoring the alarm used to monitor theAFD to OPERABLE status.*b. Monitoring and logging the indicated AFD for each OPERABLE excore channel at least enee per-hour for the first 24 hours and at least once per 30 minutes thereafter, when the alarm used tomonitor the AFD is inoperable.
The logged values of the indicated AFD shall be assumed to existduring the interval preceding each logging.
'1<4.2.1. The target flux difference of each OPERABLE excore channel shall be determined by measurement at-least per 92 Effectve Full Pwer, Days. The provisions of Specification 4.0.4 are not applicable.
4.2.1.3 fhe target flux difference shall be updated at ,east enee per 31 Effetive Full Pwer Day& by eitherdetermi g the target flux difference pursuant to Specification 4.2.1.2 above or by linear interpolation betweenthe mo recently measured value and the predicted value at the end of the cycle life. The provisions ofSpecifi ation 4.0.4 are not applicable.
In accordance with theSurveillance Frequency Control Program, the* Performance of a functional test to demonstrate OPERABILITY of the alarm used to monitor the AFD may besubstituted for this requirement.
TURKEY POINT -UNITS 3 & 43/4 2-2AMENDMENT NOS. 156 and +5-POWER DISTRIBUTION LIMITSSURVEILLANCE REQUIREMENTS 4.2.2.1 If [FQ]P as predicted by approved physics calculations is greater than [FQ]L and P is greater than PT* asdefined in 4.2.2.2, FQ(Z) shall be evaluated by MIDS (Specification 4.2.2.2),
BASE LOAD (Specification 4.2.2.3) orRADIAL BURNDOWN (Specification 4.2.2.4) to determine if FQ is within its limit [FQ]P = Predicted FQ).If [FQ]P, is less than [FO]L or P is less than PT, FQ(Z) shall be evaluated to determine if FQ(Z) is within its limit asfollows:a. Using the movable incore detectors to obtain power distribution map at any THERMAL POWERgreater than 5% of RATED THERMAL POWER.b. Increasing the measured FQ(Z) component of the power distribution map by 3% to account formanufacturing tolerances and further increasing the value by 5% to account for measurement uncertainties.
Verifying that the requirements of Specification 3.2.2 are satisfied.
M Lc. FQ(Z)< FQ(Z)Where F Q (Z) is the measured FQ(Z) increased by the allowance for manufacturing tolerances Land measurement uncertainty and F Q (Z) is the FQ limit defined in 3.2.2.d. Measuring F Q (Z) according to the following schedule:
: 1. Prior to exceeding 75% of RATED THERMAL POWER,**
after refueling,
: 2. pe. I -,e.he FLAT 09M Va.e. With the relationship specified in Specification 4.2.2.1.c above not being satisfied:
: 1) Calculate the percent F (Z) exceeds its limit by thefo1) Clcuatethe ercnt Q(Z)excedsits imi bythefollowing expression:
[F MEQ1 X100forP>_0.5
[FQ]L X K(Z)/PF- (Z) 1 X100forP
< 0.5[F Q]L X K(Z)/0.5* PT = Reactor power level at which predicted F0 would exceed its limit.** During power escalation at the beginning of each cycle, power level may be increased until a power levelfor extended operation has been achieved and power distribution map obtained.
TURKEY POINT -UNITS 3 & 43/4 2-6AMENDMENT NOS. 4-37-and
+8-POWER DISTRIBUTION LIMITSSURVEILLANCE REQUIREMENTS (Continued'
: 2) The following action shall be taken:a) Comply with the requirements of Specification 3.2.2 for FM (Z) exceeding its limit by thepercent calculated above.4.2.2.2 MIDSOperation is permitted at power above PT where PT equals the ratio of [FQ]L divided by [FQ]P if the following Augmented Surveillance (Movable Incore Detection System, MIDS) requirements are satisfied:
: a. The axial power distribution shall be measured by MIDS when required such that the limitof [FQ]L/P times K(Z) is not exceeded.
FJ(Z) is the normalized axial power distribution from thimble j at core elevation (Z).1) If Fj(Z) exceeds [Fj(Z)]s*
as defined in the bases by _< 4%, immediately reducethermal power one percent for every percent by which [Fj(Z)],
is exceeded.
: 2) If F1(Z) exceeds [Fj(Z)]s by > 4% immediately reduce thermal power below PT.Corrective action to reduce Fj(Z) below the limit will permit return to thermalpower not to exceed current PL** as defined in the bases.b. Fj(Z) shall be determined to be within limits by using MIDS to monitor the thimblesInsert 1 required per Specification 4.2.2.2.c at the following frequencies.
1 .,and2. Immediately following and as a minimum at 2, 4 and 8 hours following the eventslisted below and every 24 hours thereafter.
: 1) Raising the thermal power above PT, or2) Movement of control-bank D more than an accumulated total of 15 stepsin any one direction.
: c. MIDS shall be operable when the thermal power exceeds PT with:1) At least two thimbles available for which Rj and aj as defined in the bases havebeen determined.
[Fj(Z)]s is the alarm setpoint for MIDS.** PL is reactor thermal power expressed as a fraction of the Rated Thermal Power that is used to calculate
[Fj(Z)]s.
TURKEY POINT -UNITS 3 & 43/4 2-7AMENDMENT NOS. +8 and 47-2 POWER DISTRIBUTION LIMITSSURVEILLANCE REQUIREMENTS (Continued)
: 2. At least two movable detectors available for mapping Fj(Z).3. The continued accuracy and representativeness of the selected thimbles shall be verifiedby using the most recent flux map to update the R for each selected thimble.
The fluxmap must be updated at least o... per 31 .ff..tiv.
full pcwcr days.where: linsert 1R= Total peaking factor from a full flux map ratioed to the axial peaking factor in aselected thimble.j The thimble location selected for monitoring.
4.2.2.3 Base LoadBase Load operation is permitted at powers above PT if the following requirements are satisfied:
: a. Either of the following preconditions for Base Load operation must be satisfied.
: 1. For entering Base Load operation with power less than PT,a) Maintain THERMAL POWER between PT/1.05 and PT for at least 24 hours,b) Maintain the AFD (Delta-I) to within a +/- 2% or +/- 3% target band for at least 23hours per 24-hour period.Mc) After 24 hours have elapsed, take a full core flux map to determine FQ (Z)unless a valid full core flux map was taken within the time period specified in4.2.2.1d.
d) Calculate PBL per 4.2.2.3b.
: 2. For entering Base Load operation with power greater than PT,a) Maintain THERMAL POWER between PT and the power limit determined in4.2.2.2 for at least 24 hours, and maintain Augmented Surveillance requirements of 4.2.2.2 during this period.b) Maintain the AFD (Delta-I) to within a +/- 2% or +/- 3% target band for at least 23hours per 24-hour period,TURKEY POINT -UNITS 3 & 43/4 2-8AMENDMENT NOS. 4-3-7 and -+3-2 POWER DISTRIBUTION LIMITSSURVEILLANCE REQUIREMENTS 4.2.3.1 The provisions of Specification 4.0.4 are not applicable.
4.2.3.2 When a measurement of FN is taken, the measured FN shall be increased by 4% to account formeasurement error. AH ' H4.2.3.3 This corrected FN shall be determined to be within its limit through incore flux mapping:AHa. Prior to operation above 75% of RATED THERMAL POWER after each fuel loading, andb. At 'east enc poe 3 E-ffeetive-Full Poewer Days.TURKEY POINT -UNITS 3 & 43/,M 2-12AMENDMENT NOS. +3-7-and 42-POWER DISTRIBUTION LIMITSLIMITING CONDITION FOR OPERATION (Continued)
ACTION (Continued)
: 2. Reduce THERMAL POWER to less than 50% of RATED THERMAL POWER within 2hours and reduce the Power Range Neutron Flux-High Trip Setpoints to less than orequal to 55% of RATED THERMAL POWER within the next 4 hours; and3. Identify and correct the cause of the out-of -limit condition prior to increasing THERMALPOWER; subsequent POWER OPERATION above 50% of RATED THERMAL POWERmay proceed provided that the QUADRANT POWER TILT RATIO is verified within itslimit at least once per hour for 12 hours or until verified at 95% or greater RATEDTHERMAL POWER.d. The provisions of Specifications 3.0.4 are not applicable.
SURVEILLANCE REQUIREMENTS 4.2.4.1 The QUADRANT POWER TILT RATIO shall be determined to be within the limit above 50% of RATEDTHERMAL POWER-by:
sert 1a. Ceeulatei,,
the ratio at lcast 3,'ZZ per 7 days when the Power Range Upper Detector Hig.FluxDeviation and Power Range Lower Detector High Flux Deviation Alarms are OPERABLE, andthe ratio at least once per 12 hours during steady-state operation when either alarm is/ ~~~~inoperaoe
"'""-- B acltnZ 4.2.4.2 The QUADRANT POWER TILT RATIO shall be determined to be within the limit when above 75% ofRATED THERMAL POWER with one Power Range channel inoperable by using the movable incore detectors toconfirm that the normalized symmetric power distribution, obtained either from two sets of four symmetric thimblelocations or full-core flux map, or by incore thermocouple map is consistent with the indicated QUADRANTPOWER TILT RATIO at least once per 12 hours.4.2.4.3 If the QUADRANT POWER TILT RATIO is not within its limit within 24 hours and the POWERDISTRIBUTION LIMITS of 3.2.2 and 3.2.3 are within their limits, a Special Report in accordance with 6.9.2 shallbe submitted within 30 days including an evaluation of the cause of the discrepancy.
In accordance with theSurveillance Frequency ControlProgram by calculating TURKEY POINT -UNITS 3 & 43/4 2-15AMENDMENT NOS. 447 and 4-32 POWER DISTRIBUTION LIMITS3/4.2.5 DNB PARAMETERS LIMITING CONDITION FOR OPERATION 3.2.5 The following DNB-related parameters shall be maintained within the following limits:a. Reactor Coolant System Tavg is less than or equal to the limit specified in the COLRb. Pressurizer Pressure is greater than or equal to the limit specified in the COLR*, andc. Reactor Coolant System Flow >_ 270,000 gpmAPPLICABILITY:
MODE 1.ACTION:With any of the above parameters exceeding its limit, restore the parameter to within its limit within 2 hours orreduce THERMAL POWER to less then 5% of RATED THERMAL POWER within the next 4 hours.SURVEILLANCE REQUIREMENTS 4.2.5.1 Reactor Coolant System Tavg and Pressurizer Pressure shall be verified to be within their limitsencc per 12 hurGs.* / lnsert 14.2.5.2 RCS flow rate shall be monitored for degradation at least encc pcr ,4.2.5.3 The RCS flow rate indicators shall be subjected to a CHANNEL C TION4.2.5.4 After each fuel loading, and atle 40" h1mths, the RCS flow rate shall be determined byprecision heat balance after exceeding 90% RATED THERMAL POWER. The measurement instrumentation shall be calibrated within 90 days prior to the performance of the calorimetric flow measurement.
The provisions of 4.0.4 are not applicable for performing the precision heat balance flow measurement.
* Limit not applicable during either a THERMAL POWER ramp in excess of 5% of RATED THERMAL POWERper minute or a THERMAL POWER step in excess of 10% of RATED THERMAL POWER.TURKEY POINT -UNITS 3 & 43/4 2-16AMENDMENT NOS. 249 and 245 No changes this page,For information only I3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR TRIP SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.1 As a minimum, the Reactor Trip System instrumentation channels and interlocks of Table 3.3-1 shall beOPERABLE.
APPLICABILITY:
As shown in Table 3.3-1.ACTION:As shown in Table 3.3-1.SURVEILLANCE REQUIREMENTS 4.3.1.1 Each Reactor Trip System instrumentation channel and interlock and the automatic triplogic shall be demonstrated OPERABLE by the performance of the Reactor Trip System Instrumentation Surveillance Requirement specified in Table 4.3-1.TURKEY POINT -UNITS 3 & 43/4 3-1AMENDMENT NOS. 178 AND 172 Replace each marked throughSurveillance Frequency with "SFCP".m0-HC:90.A.TABLE 4.3-1REACTOR TRIP SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL CHANNELCHECK CALIBRATION ANALOGCHANNELOPERATIONAL TESTN.A.FUNCTIONAL UNIT1. Manual Reactor TripTRIPACTUATING DEVICEOPERATIONAL TESTN.A.N.A.N.A.ACTUATION LOGIC TESTN.A.N.A.MODES FORWHICHSURVEILLANCE IS REQUIRED1, 2, 3*, 4*, 5*1,22. Power Range, Neutron Fluxa, High Setpointcob, Low Setpoint3. Intermediate Range,Neutron Flux4. Source Range, Neutron Fluxmzmzz0C/)z5.6.7.8.9.10.11.Overtemperature ATOverpower ATPressurizer Pressure--Low Pressurizer Pressure--High Pressurizer Water Level--High Reactor Coolant Flow--Low Steam Generator Water Level--Low-LowK-."K,"E4,2, 4),'*3, 4),V44, 6),(a), (b),(4)(a),
(b)X(4)N4)&#xfd;(4)(b)(b)(b)\,a(b)S/U(1)S/U(1)S/U(1), k(g)"(a), (b)V ), (b)), (b)N.A.N.A.N.A.N.A.N.A.N.A.N.A.N.A.N.A.N.A.N.A.N.A.N.A.N.A.N.A.N.A.N.A.N.A.N.A.N.A.1"**, 21 **, 22**,3, 4, 51,21,211,2111,2 Replace each marked throughSurveillance Frequency with "SFCP".Hm0CC,,-NTABLE 4.3-1REACTOR TRIP SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS FUNCTIONAL UNIT12. Steam Generator WaterLevel--Low Coincident withSteam/Feedwater FlowMismatch13. Undervoltage-4.16 kVBusses A and B14. Underfrequency
-Trip ofReactor Coolant PumpBreakers(s)
Open15. Turbine Tripa. Emergency Trip HeaderPressureb. Turbine Stop ValveClosure16. Safety Injection Inputfrom ESF17. Reactor Trip SystemInterlocks
: a. Intermediate RangeNeutron Flux, P-6b. Low Power ReactorTrips Block, P-7(includes P-10 inputand Turbine InletPressure)
: c. Power Range NeutronFlux, P-8CHANNELCHECK'_s.CHANNELCALIBRATION
'a), (b)ANALOGCHANNELOPERATIONAL TEST-,G<, (b)TRIPACTUATING DEVICEOPERATIONAL TESTN.A.ACTUATION LOGIC TESTN.A.MODES FORWHICHSURVEILLANCE IS REQUIRED1,2N.A.N.A.N.A.N.A.N.A.N.A.S/U(1, 10)S/U(1, 10)N.A.N.A.N.A.N.A.N.A.N.A.N.A.N.A.N.A.N.A.a), (b)111,2N.A.N.A.N.A.N.A.'X~4)N.A.N.A.N.A.N.A.-P4,4)1N.A.X(4)N.A.N.A.
Replace each marked throughSurveillance Frequency with "SFCP".--C;Um0zC-z--iC/)QOTABLE 4.3-1REACTOR TRIP SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS ANALOGCHANNELOPERATIONAL TESTTRIPACTUATING DEVICEOPERATIONAL TESTCHANNEL CHANNELCHECK CALIBRATION ACTUATION LOGIC TESTMODES FORWHICHSURVEILLANCE IS REQUIREDFUNCTIONAL UNIT17. Reactor Trip System Interlocks (Continued)
: d. Power RangeNeutron Flux, P-1018. Reactor Coolant PumpBreaker Position TripO~19. Reactor Trip Breaker20. Automatic Trip and Inter-lock Logic21. Reactor Trip BypassBreakerN.A.N.A.N.A.N.A.N.A.X(4)N.A.N.A.N.A.N.A.N.A.N.A.N.A.N.A.N.A.X(7, 11)N.A.N.A.N.A.N.A.'X(,14)1, 2, 3*, 4*, 5*1, 2, 3*, 4*, 5*1,2, 3*, 4*, 5*1,21X013), X05)N.A.mzmz-Hz0z No changes this page,INSTRUMENTATION For information only 13/4.3.2 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.2 The Engineered Safety Feature Actuation System (ESFAS) instrumentation channels and interlocks shownin Table 3.3-2 shall be OPERABLE with their Trip Setpoints set consistent with the values shown in the TripSetpoint column of Table 3.3-3.APPLICABILITY:
As shown in Table 3.3-2.ACTION:a. With an ESFAS Instrumentation or Interlock Trip Setpoint less conservative than the value shownin the Trip Setpoint column but more conservative than the value shown in the Allowable Valuecolumn of Table 3.3-3, adjust the Setpoint consistent with the Trip Setpoint value withinpermissible calibration tolerance.
: b. With an ESFAS Instrumentation or Interlock Trip Setpoint less conservative than the value shownin the Allowable Value column of Table 3.3-3, either:1. Adjust the Setpoint consistent with the Trip Setpoint value of Table 3.3-3 and determine within 12 hours that the affected channel is OPERABLE; or2. Declare the channel inoperable and apply the applicable ACTION statement requirements of Table 3.3-2 until the channel is restored to OPERABLE status with itssetpoint adjusted consistent with the Trip Setpoint value.c. With an ESFAS instrumentation channel or interlock inoperable, take the ACTION shown inTable 3.3-2.SURVEILLANCE REQUIREMENTS 4.3.2.1 Each ESFAS instrumentation channel and interlock and the automatic actuation logic and relays shall bedemonstrated OPERABLE by performance of the ESFAS Instrumentation Surveillance Requirements specified inTable 4.3-2.TURKEY POINT -UNITS 3 & 43/4 3-13AMENDMENT NOS. 176 AND 170 Replace each marked throughSurveillance Frequency with "SFCP".TABLE 4.3-2H-Cm_00CZ--I(nENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS ANALOGCHANNELOPERATIONAL TESTTRIPACTUATING DEVICEOPERATIONAL TESTMODESFOR WHICHSURVEILLANCE IS REQUIREDCHANNELFUNCTIONAL UNIT1. Safety Injection CHANNEL CHANNELCHECK CALIBRATION ACTUATION LOGIC TEST #__>Kc~)C~)0)mzmzZ0Cl)za. Manual Initiation
: b. Automatic Actuation Logic and Actuation Relaysc. Containment Pressure--
Highd. Pressurizer Pressure--
Lowe. High Differential Pressure Between theSteam Line Header andany Steam Linef. Steam Line Flow--High Coincident with:Steam Generator Pressure--Low orTavg--Low N.A.N.A.N.A.N.A.N.A.N.A.N.A.N.A.'&5)\(5)"sN.A.N.A.N.A.N.A.N.AN.A.N.A.x1)W1)N.A.N.A.N.AN.A.1,2,31,2,3(3)1,2,31,2,3(3)1,2,3(3)1,2,3(3)1,2,3(3)~(b)\()(b)'G&#xfd;5) N.A.N.A. 1,2,3(3)
Replace each marked throughSurveillance Frequency with "SFCP".TABLE 4.3-2 (Continued)
ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS HC:m0zZcnWCHANNELFUNCTIONAL UNIT2. Containment Spraya. Automatic Actuation Logic and Actuation Relaysb. Containment Pressure--
High-High Coincident with:Containment Pressure--
High3. Containment Isolation
: a. Phase "A" Isolation
: 1) Manual Initiation
: 2) Automatic Actua-tion Logic andActuation Relays3) Safety Injection CHANNEL CHANNELCHECK CALIBRATION ANALOGCHANNELOPERATIONAL TESTTRIPACTUATING DEVICEOPERATIONAL TESTMODESFOR WHICHSURVEILLANCE IS REQUIREDACTUATION LOGIC TEST #N.A.N.A.N.A.N.A.N.A.N.A.N.A.N.A.\(1)1,2,3,41,2,31,2,3K'M1,)C.,N.A.N.A.N.A.N.A.N.A.N.A.N.A.h(i)1,2,3,41,2,3,4N.A.mzmzz0zSee Item 1. above for all Safety Injection Surveillance Requirements.
: b. Phase "B" Isolation
: 1) Manual Initiation
: 2) Automatic Actua-tion Logic andActuation RelaysN.A.N.A.N.A.N.A.N.A.N.A.N.A.N.A.XMi )1,2,3,41,2,3,4 Replace each marked throughSurveillance Frequency with "SFCP".TABLE 4.3-2 (Continued)
Hm-<0z-zz-H:ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS ANALOGCHANNELOPERATIONAL TESTTRIPACTUATING DEVICEOPERATIONAL TESTCHANNEL CHANNELFUNCTIONAL UNIT CHECK3. Containment Isolation (Continued)
CHANNELCALIBRATION ACTUATION LOGICTEST #MODESFOR WHICHSURVEILLANCE IS REQUIREDC',33) Containment Pressure--High-High Coincident with: Containment Pressure--High
: c. Containment Venti-lation Isolation
: 1) Containment Isolation Manual Phase Aor Manual Phase B2) Automatic Actua-tion Logic andActuation Relays3) Safety Injection
: 4) Containment Radio-activity--High
: 4. Steam Line Isolation
: a. Manual Initiation
: b. Automatic Actuation Logic and Actuation RelaysN.A.N.A.N.A.N.A.N.A.x'M~1)\1)1,2,31,2,31,2,3,4mz0mzHz0zN.A.N.A.See Item 1N.A.N.A.N.A.N.A.N.A.N.A.N.A.N.A.above for all Safety Injection Surveillance Requirements.
)Q.. _t~lN.A.N.A.N.A."M(l)1,2,3,41,2,31,2,3(3)N.A.N.A.N.A.N.A.N.A.
Replace each marked throughSurveillance Frequency with "SFCP".TABLE 4.3-2 (Continued) m0zZC/)Cl)W,ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS ANALOGCHANNELOPERATIONAL TESTTRIPACTUATING DEVICEOPERATIONAL TESTMODESFOR WHICHSURVEILLANCE IS REQUIREDCHANNELFUNCTIONAL UNITCHANNEL CHANNELCHECK CALIBRATION ACTUATION LOGIC TEST #4. Steamline Isolation (Continued)
: c. Containment Pressure--
High-High Coincident with:Containment Pressure--
Highd. Steam Line Flow--High Coincident with:Steam Generator Pressure--Low orTavg--Low
: 5. Feedwater Isolation
: a. Automatic Actuation Logic and Actuation Relaysb. Safety Injection
: c. Steam Generator WaterLevel--High-High
: 6. Auxiliary Feedwater (2)a. Automatic Actuation Logic and Actuation Relaysb. Steam Generator Water Level--Low-Low N.A.N.A.X(3)\(3)N.A.N.A'M~1)~P4Q)", a)(b)&#xfd;(5)(a)(b)
N.A.N.A.N.A.N.A.N.A.N.A.N.A.1,2,31,2,31,2,31,2,31,2,31,2,3N.A.N.A.N.A.IlZz--iz09zSee Item 1. above for all Safety Injection Surveillance Requirements.
"b)N.A.N.A.a)b)N.A.)(b)N.A.N.A.N.A.N.A.1,2,31,2,31,2,3)Ra(b)N.A.N~K Replace each marked throughSurveillance Frequency with "SFCP".TABLE 4.3-2 (Continued) m0zCzCl-iENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS ANALOGCHANNELOPERATIONAL TESTTRIPACTUATING DEVICEOPERATIONAL TESTCHANNEL CHANNEL CHANNELFUNCTIONAL UNIT CHECK CALIBRATION
: 6. Auxiliary Feedwater (Continued)
: c. Safety Injection See Item 1. above for all Safetyd. Bus Stripping N.A.e. Trip of All Main N.A. N.A.Feedwater PumpBreakers.
: 7. Loss of Powera. 4.16 kV busses A N.A. "R,and B (Loss ofVoltage)b. 480V Load Centers3A, 3B, 3C, 3D and4A, 4B, 4C, 4DUndervoltage ACTUATION LOGIC TEST #MODESFOR WHICHSURVEILLANCE IS REQUIREDInjection Surveillance Requirements.
N.A.N.A.N.A.N.A.1,2,31.2C,,N.A.N.A.N.A.N.A.1,2,3,41,2,3,4NM,(1)Zmzmz-Iz0zCoincident with:Safety Injection
: c. 480V Load Centers3A, 3B, 3C, 3D and4A, 4B, 4C, 4DDegraded VoltageSee Item 1. above for all Safety Injection Surveillance Requirements.
KN.A.N.A.1,2,3,4 Replace each marked throughSurveillance Frequency with "SFCP".TABLE 4.3-2 (Continued)
ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS
-HC0Hm--IC"coz90.P.ANALOGCHANNELOPERATIONAL TESTTRIPACTUATING DEVICEOPERATIONAL TESTMODESFOR WHICHSURVEILLANCE IS REQUIREDCHANNELFUNCTIONAL UNIT8. Engineering SafetyFeatures Actuation System Interlocks
: a. Pressurizer Pressureb. Tavg--Low
: 9. Control Room Ventilation Isolation
: a. Automatic Actuation Logic and Actuation Relaysb. Safety Injection
: c. Containment Radioactivity--High
: d. Containment Isolation Manual Phase A orManual Phase Be. Control Room AirIntake Radiation LevelCHANNEL CHANNELCHECK CALIBRATION ACTUATION LOGIC TEST #N.A.N.A.N.A.&#xfd;(5)X_N.A.N.A.N.A.N.A.N.A.N.A.1,2,3(3)1,2,3(3)N.A.N.A.See Item 1. above for all Safety Injection Surveillance Requirements.
"& 1_RM. N.A.N.A.N.A.N.A.N.A.N.A.N.A.(4)1,2,3,4AllmzmZz0Iiz0N.A.
INSTRUMENTATION 3/4.3.3 MONITORING INSTRUMENTATION No changes this page,For information only'RADIATION MONITORING FOR PLANT OPERATIONS LIMITING CONDITION FOR OPERATION 3.3.3.1 The radiation monitoring instrumentation channels for plant operations shown in Table 3.3-4 shall beOPERABLE with their Alarm/Trip Setpoints within the specified limits.APPLICABILITY:
As shown in Table 3.3-4.ACTION:a. With a radiation monitoring channel Alarm/Trip Setpoint for plant operations exceeding the valueshown in Table 3.3-4, adjust the Setpoint to within the limit within 4 hours or declare the channelinoperable.
: b. With one or more radiation monitoring channels for plant operations inoperable, take the ACTIONshown in Table 3.3-4.c. The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.3.3.1 Each radiation monitoring instrumentation channel for plant operations shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL CALIBRATION and ANALOG CHANNELOPERATIONAL TEST for the MODES and at the frequencies shown in Table 4.3-3.TURKEY POINT -UNITS 3 & 43/4 3-35AMENDMENT NOS. 137 AND 132 ACTION 27 -lTABLE 3.3-4 (Continued)
ACTION STATEMENTS (Continued)
In MODES 5 or 6 (e-peet during CORE ALTERATION or movement of irradiated fuel within thecontainment):
With the number of OPERABLE Channels less than the Minimum ChannelsOPERABLE requirement perform the following:
.1) Obtain and analyze appropriate grab samples at least once per 24 hours, and2) Monitor containment atmosphere with area radiation monitors.
Otherwise, isolate all penetrations that provide direct access from the containment atmosphere tothe outside atmosphere.
During CORE ALTERATION or movement of irradiated fuel within the containment:
With thenumber of OPERABLE Channels less than the Minimum Channels OPERABLE requirements, comply with ACTION statement requirements of Specification 3.9.9 and 3.9.13.With the number of OPERABLE channels less than the Minimum Channels OPERABLErequirement, immediately suspend operations in the Spent Fuel Pool area involving spent fuelmanipulations.
ACTION 28 -TURKEY POINT -UNITS 3 & 43/4 3-38AMENDMENT NOS. 1 AND 4-32 Replace each marked throughc Surveillance Frequency with "SFCP".XTABLE 4.3-3m RADIATION MONITORING INSTRUMENTATION FOR PLANTOPERATIONS SURVEILLANCE REQUIREMENTS 0ANALOG MODES FORI CHANNEL WHICHc CHANNEL CHANNEL OPERATIONAL SURVEILLANCE z FUNCTIONAL UNIT CHECK CALIBRATION TEST IS REQUIREDU')1. Containment
: a. Containment Atmosphere  -R-- AllRadioactivity--High
: b. RCS Leakage Detection
: 1) Particulate Radio- -&-- -R- -1, 2, 3, 4activity2) Gaseous Radioactivity
_S-- -R--- -Q- 1, 2, 3, 42. Spent Fuel Pool Areasa. Unit 3 Radioactivity--High Gaseous --S- -R-b. Unit 4 (Plant Vent)Radioactivity--High
:> Gaseous#r (SPING and PRMS) ----0z--* With irradiated fuel in the fuel storage pool areas.0O' # Unit 4 Spent Fuel Pool Area is monitored by Plant Vent radioactivity instrumentation.
z INSTRUMENTATION MOVABLE INCORE DETECTORS LIMITING CONDITION FOR OPERATION 3.3.3.2 The Movable Incore Detection System shall be OPERABLE with:a. At least 16 detector thimbles when used for recalibration and check of the Excore Neutron FluxDetection System and monitoring the QUANDRANT POWER TILT RATIO*, and at least 38detector thimbles when used for monitoring FNH FQ(Z) and FY(Z).b. A minimum of two detector thimbles per core quadrant, andc. Sufficient movable detectors, drive, and readout equipment to map these thimbles.
APPLICABLITY:
When the Movable Incore Detection System is used for:a. Recalibration of the Excore Neutron Flux Detection System, orb. Monitoring the QUADRANT POWER TILT RATIO*, orc. Measurement of FNH, FQ(Z) and Fxl(Z).ACTION:With the Movable Incore Detection System inoperable, do not use the system for the above applicable monitoring or calibration functions.
The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.3.3.2 The Movable Incore Detection System shall be demonstrated OPERABLE at Ieas e r 24 hg'-s bynormalizing each detector output when required for:a. Recalibration of the Excore Neutron Flux Detection System, orb. Monitoring the QUADRANT POWER TILT RATIO*, or lFnsert 1ic. Measurement of FNH, FQ(Z) and Fxy(Z).* Exception to the 16 detector thimble requirement of monitoring the QUADRANT POWER TILT RATIO isacceptable when performing Specification 4.2.4.2 using two sets of four symmetric thimbles.
TURKEY POINT -UNITS 3 & 43/4 3-40AMENDMENT NOS. 1--7-AND 1-3 INSTRUMENTATION No changes this page,[For information onlyACCIDENT MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.3.3 The accident monitoring instrumentation channels shown in Table 3.3-5 shall be OPERABLE.
APPLICABILITY:
As shown in Table 3.3-5.ACTION:a. As shown in Table 3.3-5.b. The provisions of Specification 3.0.4 are not applicable to ACTIONS in Table 3.3-5 that require ashutdown.
: c. Separate Action entry is allowed for each Instrument.
SURVEILLANCE REQUIREMENTS 4.3.3.3 Each accident monitoring instrumentation channel shall be demonstrated OPERABLE by performance ofthe CHANNEL CHECK and CHANNEL CALIBRATION at the frequencies shown in Table 4.3-4.TURKEY POINT -UNITS 3 & 43/4 3-41AMENDMENT NOS. 227 AND 223 Replace each marked throughSurveillance Frequency with "SFCPR.TABLE 4.3-4ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL CHANNELINSTRUMENT CHECK CALIBRATION
: 1. Containment Pressure (Wide Range) -m- -R-2. Containment Pressure (Narrow Range) -f-3. Reactor Coolant Outlet Temperature
-THOT W(Wide Range)4. Reactor Coolant Inlet Temperature
-TCOLD -(Wide Range)5. Reactor Coolant Pressure
-Wide Range M -R-6. Pressurizer Water Level --R-7. Auxiliary Feedwater Flow Rate -MR----8. Reactor Coolant System Subcooling Margin Monitor -- -R--9. PORV Position Indicator (Primary Detector)
--M- -R-10. PORV Block Valve Position Indicator M11. Safety Valve Position Indicator (Primary Detector)
M -R--12. Containment Water Level (Narrow Range) Ml13. Containment Water Level (Wide Range) M --R-14. In Core Thermocouples (Core Exit Thermocouples)
-R-M---15. Containment
-High Range Area Radiation Monitor 16. Reactor Vessel Level Monitoring System17. Neutron Flux, Backup NIS (Wide Range) M -R---18. DELETED19. High Range -Noble Gas Effluent Monitorsa. Plant Vent Exhaust M -R-b. Unit 3 -Spent Fuel Pit Exhaust -M--- -c. Condenser Air Ejectors
-M-20. RWST Water Level M -R--21. Steam Generator Water Level (Narrow Range) -W -R-22. Containment Isolation Valve Position Indication
*Acceptable criteria for calibration are provided in Table II.F. 1-3 of NUREG-0737.
TURKEY POINT -UNITS 3 & 43/4. 3-46AMENDMENT NOS. 2-6-AND 2*e-No changes this page,For information only IINSTRUMENTATION EXPLOSIVE GAS MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.3.6 The explosive gas monitoring instrumentation channels shown in Table 3.3-8 shall be OPERABLEwith their Alarm/Trip Setpoints set to ensure that the limits of Specification 3.7.8 are not exceeded.
APPLICABILITY:
As shown in Table 3.3-8ACTION:a. With an explosive gas monitoring instrumentation channel Alarm/Trip Setpoint lessconservative than required by the above specification, declare the channel inoperable orchange the setpoint so it is acceptably conservative.
: b. With less than the minimum number of explosive gas monitoring instrumentation channels
: OPERABLE, take the ACTION shown in Table 3.3-8. Restore the inoperable instrumentation to OPERABLE status within 30 days and, if unsuccessful prepareand submit a special report to the Commission within 30 days to explain why thisinoperability was not corrected in a timely manner.c. The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.3.3.6 Each explosive gas monitoring instrumentation channel shall be demonstrated OPERABLE byperformance of the CHANNEL CHECK, CHANNEL CALIBRATION and ANALOG CHANNELOPERATIONAL TEST at the frequencies shown in Table 4.3-6.TURKEY POINT -UNITS 3 & 43/4 3-47AMENDMENT NOS. 188 AND 182 Replace each marked through-Surveillance Frequency with "SFCP".CZXTABLE 4.3-6mEXPLOSIVE GAS MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS 0zANALOG MODES FORz CHANNEL WHICHCHANNEL SOURCE CHANNEL OPERATIONAL SURVEILLANCE ISINSTRUMENT CHECK CHECK CALIBRATION TEST REQUIRED1. GAS DECAYTANK SYSTEM(Explosive Gas Monitoring System)a. Hydrogen and Oxygen Monitors
---- N.A. X0 1,2) -M- *TABLE NOTATIONDuring GAS DECAY TANK SYSTEM operation.
(1) The CHANNEL CALIBRATION shall include the use of standard gas samples containing a nominal.a. One volume percent hydrogen, balance nitrogen, andb. Four volume percent hydrogen, balance nitrogen.
> (2) The CHANNEL CALIBRATION shall include the use of standard gas samples containing a nominal:mz a. One volume percent oxygen, balance nitrogen, andm b. Four volume percent oxygen, balance nitrogen.
z-Hz0z 3/4.4 REACTOR COOLANT SYSTEM3/4.4.1 REACTOR COOLANT LOOPS AND COOLANT CIRcULATION STARTUP AND POWER OPERATION LIMITING CONDITION FOR OPERATION 3.4.1.1 All reactor coolant loops shall be in operation.
APPLICABILITY:
MODES I and 2.ACTION:With less than the above required reactor coolant loops in operation, be in at least HOT STANDBY within 6 hours.SURVEILLANCE REQUIREMENTS 4.4.1.1 The above required reactor coolant loops shall be verified in operation and circulating reactor coolant at-least ounc.-p 12 Iiuur.Ilnsert 1TURKEY POINT -UNITS 3 & 43/4 4-1AMENDMENT NOS.--137AND4 REACTOR COOLANT SYSTEMHOT STANDBYLIMITING CONDITION FOR OPERATION 3.4.1.2 All of the reactor coolant loops listed below shall be OPERABLE with all reactor coolant loops inoperation when the Reactor Trip breakers are closed and two reactor coolant loops listed below shall beOPERABLE with at least one reactor coolant loop in operation when the Reactor Trip breakers are open:*a. Reactor Coolant Loop A and its associated steam generator and reactor coolant pump,b. Reactor Coolant Loop B and its associated steam generator and reactor coolant pump, andc. Reactor Coolant Loop C and its associated steam generator and reactor coolant pump.APPLICABILITY:
MODE 3ACTION:a. With less than the above required reactor coolant loops OPERABLE, restore the required loopsto OPERABLE status within 72 hours or be in HOT SHUTDOWN within the next 12 hours.b. With less than three reactor coolant loop in operation and the Reactor Trip breakers in the closedposition, within 1 hour open the Reactor Trip breakers.
: c. With no reactor coolant loop in operation, suspend all operations involving a reduction in boronconcentration of the Reactor Coolant System and immediately initiate corrective action to returnthe required reactor coolant loop to operation.
SURVEILLANCE REQUIREMENTS 4.4.1.2.1 At least the above required reactor coolant pumps, if not in operation, shall be determined OPERABLEneee per 7- day- by verifying correct breaker alignments and indicated power availabil.
4.4.1.2.2 The required steam generators shall be determined OPERABLE b erifying secondary side waterlevel to be greater than or equal to 10% at lcas' zncz por 12 hours.4.4.1.2.3 The required reactor coolant loo shall be verifie i operation and circulating reactor coolant at-east-ocrc pcr 12 houre.
1f* All reactor coolant pumps may be deenergized for up to 1 hour provided:
(1) no operations are permitted thatwould cause dilution of the Reactor Coolant System boron concentration, and (2) core outlet temperature ismaintained at least 1 OF below saturation temperature.
TURKEY POINT -UNITS 3 & 43/4 4-2AMENDMENT NOS. 97- AND-1-REACTOR COOLANT SYSTEMSURVEILLANCE REQUIREMENTS 4.4.1.3.1 The required reactor coolant pump(s),
if not in operation, shall be determined OPERABLE eneepff4-days-by verifying correct breaker alignments and indicated power availabilit 4.4.1.3.2 The required steam generator(s) shall be determined OPERAB by verifying secondary side waterlevel to be greater than or equal to 10% at least oence Pc 12 h.. rz.4.4.1.3.3 At least one reactor coolant or RHR looT shall be verifie n operation and circulating reactor coolant ate a .......elII t 41 ; qA 1TURKEY POINT -UNITS 3 & 43/4 4-4AMENDMENT NOS. i-37 AND 432-REACTOR COOLANT SYSTEMCOLD SHUTDOWN
-LOOPS FILLEDLIMITING CONDITION FOR OPERATION 3.4.1.4.1 At least one residual heat removal (RHR) loop shall be OPERABLE and in operation*,
and either:a. One additional RHR loop shall be OPERABLE**,
orb. The secondary side water level of at least two steam generators shall be greater than 10%.APPLICABILITY:
MODE 5 with reactor coolant loops filled***.
ACTION:a. With one of the RHR loops inoperable or with less than the required steam generator water level,immediately initiate corrective action to return the inoperable RHR loop to OPERABLE status orrestore the required steam generator water level as soon as possible.
: b. With no RHR loop in operation, suspend all operations involving a reduction in boronconcentration of the Reactor Coolant System and immediately initiate corrective action to returnthe required RHR loop to operation.
SURVEILLANCE REQUIREMENTS 4.4.1.4.1.1 The secondary side water level of at least two steam generators when required shall be determined to be within limits at least per 12 hours.4.4.1.4.1.2 At least one RHR loop sh~abe determined to be in operation and circulating reactor coolant a-teast* The RHR pump may be deenergized for up to 1 hour provided:
(1) no operations are permitted that wouldcause dilution of the Reactor Coolant System boron concentration, and (2) core outlet temperature ismaintained at least 1 0&deg;F below saturation temperature.
** One RHR loop may be inoperable for up to 2 hours for surveillance testing provided the other RHR loop isOPERABLE.
* A reactor coolant pump shall not be started with one or more of the Reactor Coolant System cold legtemperatures less than or equal to 275&deg;F unless the secondary water temperature of each steam generator is less than 50'F above each of the Reactor Coolant System cold leg temperatures.
TURKEY POINT -UNITS 3 & 43/4 4-5AMENDMENT NOS. 1--AND 4K REACTOR COOLANT SYSTEMCOLD SHUTDOWN
-LOOPS NOT FILLEDLIMITING CONDITION FOR OPERATION 3.4.1.4.2 Two residual heat removal (RHR) loops shall be OPERABLE*
and at least one RHR loop shall be inoperation.**
APPLICABILITY:
MODE 5 with reactor coolant loops not filled.ACTION:a. With less than the above required RHR loops OPERABLE, immediately initiate corrective actionto return the required RHR loops to OPERABLE status as soon as possible.
: b. With no RHR loop in operation, suspend all operations involving a reduction in boronconcentration of the Reactor Coolant System and immediately initiate corrective action to returnthe required RHR loop to operation.
SURVEILLANCE REQUIREMENTS 4.4.1.4.2 At least one RHR loop shall be determined to be in operation and circulating reactor coolant a-4easAoInsert 1One RHR loop may be inoperable for up to 2 hours for surveillance testing provided the other RHR loop isOPERABLE.
** The RHR pump may be deenergized for up to 1 hour provided:
(1) no operations are permitted that wouldcause dilution of the Reactor Coolant System boron concentration, and (2) core outlet temperature ismaintained at least 1 OF below saturation temperature.
TURKEY POINT -UNITS 3 & 43/4 4-6AMENDMENT NOS. 4,7 AND 432-REACTOR COOLANT SYSTEM3/4.4.3 PRESSURIZER LIMITING CONDITION FOR OPERATION 3.4.3 The pressurizer shall be OPERABLE with a water volume of less than or equal to 92% of indicated level,and at least two groups of pressurizer heaters each having a capacity of at least 125 kW and capable of beingsupplied by emergency power.APPLICABILITY:
MODES 1, 2, and 3.ACTION:a. With only one group of pressurizer heaters OPERABLE, restore at least two groups toOPERABLE status within 72 hours** or be in at least HOT STANDBY within the next 6 hours andin HOT SHUTDOWN within the following 6 hours.b. With the pressurizer otherwise inoperable, be in at least HOT STANDBY with the Reactor TripSystem breakers open within 6 hours and in HOT SHUTDOWN within the following 6 hours.SURVEILLANCE REQUIREMENTS 4.4.3.1 The pressurizer water volume shall be determined to be within its limit -t I c p. 12 hours.4.4.3.2 The capacity of each of the above required groups of pressurizer heate shall be verified to be at least '4/125 kw at ,ea-st ocme- per, 1 i L 1 Qt ..14 days if the inoperability is associated with an inoperable diesel generator.
TURKEY POINT -UNITS 3 & 43/4 4-9AMENDMENT NOS.-?&#xfd;-AND 2.2 7Insert 1REACTOR COOLANT SYSTEME LLIEF VALVESS VEILLANCE REQUIREMENT Each block valve shall be demonstrated OPERABLE at least e.. per 92 days. by operating the valvethrough one complete cycle of full travel unless the block valve is closed with power removed in order to meet therequirements of Specification 3.4.4 or is closed to provide an isolation function.
TURKEY POINT -UNITS 3 & 43/4 4-10OaAMENDMENT NOS. 1-" AND REACTOR COOLANT SYSTEM3/4.4.6 REACTOR COOLANT SYSTEM LEAKAGELEAKAGE DETECTION SYSTEMSLIMITING CONDITION FOR OPERATION 3.4.6.1 The following Reactor Coolant System Leakage Detection Systems shall be OPERABLE:
: a. The Containment Atmosphere Gaseous or Particulate Radioactivity Monitoring System, andb. A Containment Sump Level Monitoring System.APPLICABILITY:
MODES 1, 2, 3 and 4.ACTION:a. With both the Particulate and Gaseous Radioactivity Monitoring Systems inoperable, operation may continue for up to 7 days provided:
: 1) A Containment Sump Level Monitoring System is OPERABLE;
: 2) Appropriate grab samples are obtained and analyzed at least once per 24 hours;3) A Reactor Coolant System water inventory balance is performed at least once per 8*hours except when operating in shutdown cooling mode; and4) Containment Purge, Exhaust and Instrument Air Bleed valves are maintained closed.**
>1<Otherwise, be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWNwithin the following 30 hours.b. With no Containment Sump Level Monitoring System operable, restore at least one Containment Sump Level Monitoring System to OPERABLE status within 7 days, or be in at least HOTSTANDBY within 6 hours and in COLD SHUTDOWN within the following 30 hours.SURVEILLANCE REQUIREMENTS 4.4.6.1 The Leakage Detection System shall be demonstrated OPERABLE by:a. Containment Atmosphere Gaseous and Particulate Monitoring System-performance ofCHANNEL CHECK, CHANNEL CALIBRATION and ANALOG CHANNEL OPERATIONAL TESTat the frequencies specified in Table 4.3-3, andb. Containment Sump Level Monitoring System-performance of CHANNEL CALIBRATIO at-least-on ce pei :i 8 nniTth-,s
[Insert 1 1* Not required to be performed until 12 hours after establishment of steady state operation.
** Instrument Air Bleed valves may be opened intermittently under administrative controls.
TURKEY POINT -UNITS 3 & 4 3/4 4-18 AMENDMENT NOS. -249 AND-24 REACTOR COOLANT SYSTEMOPERATIONAL LEAKAGELIMITING CONDITION FOR OPERATION (Continued)-
: 2. The leakage*
from the remaining isolating valves in each high pressure line having avalve not meeting the criteria of Table 3.4-1, as listed in Table 3.4-1, shall be determined and recorded daily. The positions of the other valves located in the high pressure linehaving the leaking valve shall be recorded daily unless they are manual valves locatedinside containment.
Otherwise be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWNwithin the following 30 hours.d. With any Reactor Coolant System Pressure Isolation Valve leakage greater than 5 gpm, reduceleakage to below 5 gpm within 1 hour, or be in at least HOT STANDBY within the next 6 hoursand in COLD SHUTDOWN within the following 30 hours.SURVEILLANCE REQUIREMENTS 4.4.6.2.1 Reactor Coolant System operational leakages shall be demonstrated to be within each of theabove limits by:a. Monitoring the containment atmosphere gaseous or particulate radioactivity monitor at least eRee-per 12 hutirs.b. Monitoring the containment sump level .aI etT.Insert 1c. Performance of a Reactor Coolant System water inventory balance + -or 72***-haors; and _7d. Monitoring the Reactor Head Flange Leakoff System at let .... r h s ande. Verifying primary-to-secondary leakage is < 150 gallons per day through any one SG at-lea-s 4<4.4.6.2.2 Each Reactor Coolant System Pressure Isolation Valve specified in Table 3.4-1 shall beInsert 1 -demonstrated OPERABLE by verifying leakage*
to be within its limit:a. At least orce er 18 menthS.b. Prior to entering MODE 2 whenever the plant has been in COLD SHUTDOWN for 7 days or moreand if leakage testing has not been performed in the previous 9 months, andc. Prior to returning the valve to service following maintenance, repair or replacement work on thevalve.* To satisfy ALARA requirements, leakage may be measured indirectly (as from the performance of pressureindicators) if accomplished in accordance with approved procedures and supported by computations showingthat the method is capable of demonstrating valve compliance with the leakage criteria.
** Not applicable to primary-to-secondary leakage.* Not required to be performed until 12 hours after establishment of steady state operation.
TURKEY POINT -UNITS 3 & 43/4 4-20AMENDMENT NOS.--3-AND2 REACTOR COOLANT SYSTEM No changes this page,YFor information only3/4.4.7 CHEMISTRY LIMITING CONDITION FOR OPERATION 3.4.7 The Reactor Coolant System chemistry shall be maintained within the limits specified in Table 3.4-2.APPLICABILITY:
At all times.ACTION:MODES 1, 2, 3 and 4:a. With any one or more chemistry parameter in excess of its Steady-State Limit but within itsTransient Limit, restore the parameter to within its Steady-State Limit within 24 hours or be in atleast HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30hours; andb. With any one or more chemistry parameter in excess of its Transient Limit, be in at least HOTSTANDBY within 6 hours and in COLD SHUTDOWN within the following 30 hours.At All Other Times:With the concentration of either chloride or fluoride in the Reactor Coolant System in excess of itsSteady-State Limit for more than 24 hours or in excess of its Transient Limit, reduce the pressurizer pressure to less than or equal to 500 psig, if applicable, and perform an engineering evaluation todetermine the effects of the out-of-limit condition on the structural integrity of the Reactor CoolantSystem; determine that the Reactor Coolant System remains acceptable for continued operation priorto increasing the pressurizer pressure above 500 psig or prior to proceeding to MODE 4.SURVEILLANCE REQUIREMENTS 4.4.7 The Reactor Coolant System chemistry shall be determined to be within the limits by analysis of thoseparameters at the frequencies specified in Table 4.4-3.TURKEY POINT -UNITS 3 & 43/4 4-23AMENDMENT NOS. 137 AND 132 Replace each marked throughSurveillance Frequency with "SFCP".ITABLE 4.4-3REACTOR COOLANT SYSTEMCHEMISTRY LIMITS SURVEILLANCE REQUIREMENTS PARAMETER Dissolved Oxygen*SAMPLE AND ANALYSIS FREQUENCY At 'east 5 times per week not toexeeed 72 hours betweGn sampler,At 'east 5 times pef wock r-not teexceed 72 h,-rs be..Aeen samplesAt least 5 timer, p@r wak not toexceo-Rd-722 hGLurc betvwzcn
,=ampleaChloride**
Fluoride**
* Not required with average reactor coolant temperature less than or equal to 250'F.** Not required when reactor is defueled and RCS forced circulation is unavailable.
TURKEY POINT -UN!TS 3 & 43/4 4-25AMENDMENT NOS. - AND 143-2 REACTOR COOLANT SYSTEM No change this page,Ifor information only I3/4.4.8 SPECIFIC ACTIVITYLIMITING CONDITION FOR OPERATION 3.4.8 The specific activity of the primary coolant shall be limited to:a. Less than or equal to 0.25 microcuries per gram DOSE EQUIVALENT 1-131, andb. Less than or equal to 447.7 microcuries per gram DOSE EQUIVALENT XE-1 33.APPLICABILITY:
MODES 1, 2, 3, and 4.ACTION:a. With the specific activity of the reactor coolant greater than 0.25 microcuries per gram DOSEEQUIVALENT 1-131, verify DOSE EQUIVALENT 1-131 is less than or equal to 60 microcuries per gram once per 4 hours.b. With the specific activity of the reactor coolant greater than 0.25 microcuries per gram DOSEEQUIVALENT 1-131, but less than or equal to 60 microcuries per gram, operation may continuefor up to 48 hours while efforts are made to restore DOSE EQUIVALENT 1-131 to within the0.25 microcuries per gram limit. Specification 3.0.4 is not applicable.
: c. With the specific activity of the reactor coolant greater than 0.25 microcuries per gram DOSEEQUIVALENT 1-131 for greater than or equal to 48 hours during one continuous time interval, or greater than 60 microcuries per gram DOSE EQUIVALENT 1-131, be in HOT STANDBYwithin 6 hours and COLD SHUTDOWN within the next 30 hours.d. With the specific activity of the reactor coolant greater than 447.7 microcuries per gram DOSEEQUIVALENT XE-1 33, operation may continue for up to 48 hours while efforts are made torestore DOSE EQUIVALENT XE-133 to within the 447.7 microcuries per gram limit.Specification 3.0.4 is not applicable.
: e. With the specific activity of the reactor coolant greater than 447.7 microcuries per gram DOSEEQUIVALENT XE-133 for greater than or equal to 48 hours during one continuous timeinterval, be in HOT STANDBY within 6 hours and COLD SHUTDOWN within the next 30 hours.SURVEILLANCE REQUIREMENTS 4.4.8 The specific activity of the reactor coolant shall be determined to be within the limits by performance of thesampling and analysis program of Table 4.4-4.TURKEY POINT -UNITS 3 & 43/4 4-26AMENDMENT NOS. 244 AND 240 m0zC-ch,TABLE 4.4-4REACTOR COOLANT SPECIFIC ACTIVITY SAMPLE AND ANALYSIS PROGRAMTYPE OF MEASUREMENT AND ANALYSIS1. NOT USED2. Tritium ActivityDetermination
: 3. Isotopic Analysis forDOSE EQUIVALENT 1-1314. Radiochemical IsotopicDetermination Including Gaseous Activity5. Isotopic Analysis for DOSEEQUIVALENT XE-133SAMPLE AND ANALYSISFREQUENCY MODES IN WHICH SAMPLEAND ANALYSIS REQUIREDb) One sample between 2and 6 hours following a Insert 1THERMAL POWER changeexceeding 15% of theRATED THERMAL POWERwithin a 1 hour period.1,2,3,41,2,3,41,2,3,41,2,3,4co> 6. NOT USEDmzmz0zo0z REACTOR COOLANT SYSTEMOVERPRESSURE MITIGATING SYSTEMSSURVEILLANCE REQUIREMENTS 4.4.9.3.1 Each PORV shall be demonstrated OPERABLE by:a. Performance of an ANALOG CHANNEL OPERATIONAL TEST* on the PORV actuation channelfbut excluding valve operation, within 31 days prior to entering a condition in which the PORV isrequired OPERABLE and at least once per 31 days thereafter when the PORV is requiredOPERABLE.
: b. Performance of a CHANNEL CALIBRATION on the PORV actuation channel ,2t lpst encc perc. Verifying the PORV block valve is open at loact onco por 72 hauwrwhen the PORV is being usedfor overpressure protection.
: d. While the PORVs are required to be OPERABLE, the backup nitrogen supply shall be verifiedOPERABLE at* ls e4.4.9.3.2 The 2.20 square inch vent shall e verified to be open at least once per 12 heurs** when the vent(s) is4h.being used for overpressure protectionY' 4.4.9.3.3 Verify the high pressure injec on fl w path to the RCS is isolated at least Qnce per 24 hors by closedvalves with power removed or by locked lose manual valvInsert 1Not required to be met until 12 hours after decreasing RCS cold leg temperature to < 2750F.** Except when the vent pathway is provided with a valve which is locked, sealed, or otherwise secured in theopen position, then verify these valves open at least once per 31 days.TURKEY POINT -UNITS 3 & 43/4 4-37AMENDMENT NOS. 2-G8 AND-202 REACTOR COOLANT SYSTEM3/4.4.11 REACTOR COOLANT SYSTEM VENTSLIMITING CONDITION FOR OPERATION 3.4.11 At least one Reactor Coolant System vent path consisting of at least two vent valves in series andpowered from emergency busses shall be OPERABLE and closed at each of the following locations:
: a. Reactor vessel head, andb. Pressurizer steam spaceAPPLICABILITY:
MODES 1, 2, 3, and 4.ACTION:a. With one of the above Reactor Coolant System vent paths inoperable, STARTUP and/or POWEROPERATION may continue provided the inoperable vent path is maintained closed with powerremoved from the valve actuator of all the vent valves in the inoperable vent path; restore theinoperable vent path to OPERABLE status within 30 days, or, be in HOT STANDBY within 6hours and in COLD SHUTDOWN within the following 30 hours.b. With both Reactor Coolant System vent paths inoperable; maintain the inoperable vent pathclosed with power removed from the valve actuators of all the vent valves in the inoperable ventpaths, and restore at least one of the vent paths to OPERABLE status within 72 hours or be inHOT STANDBY within 6 hours and in COLD SHUTDOWN within the following 30 hours.Insert 1R ESURVEILLANCE REQUIREMENTS 4.4.11 Each Reactor Coolant System vent path shall be demonstrated OPERABLE at leastby:oncc p8r 18 monRthSa. Verifying all manual isolation valves in each vent path are locked in the open position,
: b. Cycling each vent valve through at least one complete cycle of full travel from the control room,andc. Verifying flow through the Reactor Coolant System vent paths during venting.TURKEY POINT -UNITS 3 & 43/4 4-39AMENDMENT NOS. 4---7AND 442 3/4.5 EMERGENCY CORE COOLING SYSTEMS3/4.5.1 ACCUMULATORS LIMITING CONDITION FOR OPERATION 3.5.1 Each Reactor Coolant System (RCS) accumulator shall be OPERABLE.
APPLICABILITY:
MODES 1, 2, and 3*.ACTION:a. With one accumulator inoperable, except as a result of boron concentration not being withinlimits, restore the inoperable accumulator to OPERABLE status within 1 hour or be in atleast HOT STANDBY within the next 6 hours and reduce pressurizer pressure to less than1000 psig within the following 6 hours.b. With one accumulator inoperable due to the boron concentration not being within the limits,restore boron concentration back to the required limits within 72 hours, or be in at leastHOT STANDBY within 6 hours and reduce pressurizer pressure to less than 1000 psigwithin the following 6 hours.SURVEILLANCE REQUIREMENTS 4.5.1.1 Each accumulator shall be demonstrated OPERABLE:
1sta. At 'east uonc per 12 ho~s oy:1) Verifying the borated water volume in each accumulator is between 6520 and 6820gallons, and2) Verifying that the nitrogen cover pressure in each accumulator is between 600 and675 psig, and3) Verifying that each accumulator isolation valve is open by control room indication (power may be restored to the valve operator to perform this surveillance if redundant indicator is inoperable).
*Pressurizer pressure above 1000 psig.TURKEY POINT -UNITS 3 & 43/4 5-1AMENDMENT NOS. 4-86-AND W4 EMERGENCY CORE COOLING SYSTEMSSURVEILLANCE REQUIREMENTS (Continued)
: b. At 'east zn.. pe. 31 days and within 6 hours after each solution volume increase of greater thanir equal to 1% of tank volume by verifying the boron concentration of the solution in the water-filled accumulator is between 2300 and 2600 ppm;Insert 1 c. .V49,t O,,c POP 3 ! d@.;' when the RCS pressure is above 1000 psig, by verifying that thepower to the isolation valve operator is disconnected by a locked open breaker.d. , each accumulator check valve shall be checked for operability.
TURKEY POINT -UNITS 3 & 43/4 5-2AMENDMENT NOS. A-9"AND 24-5 EMERGENCY CORE COOLING SYSTEMSSURVEILLANCE REQUIREMENTS 4.5.2 Each ECCS component and flow path shallbe demonstrated OPERABLE:
: a. At lesat once per 12 h1u.ro by verifying by control room indication that the following valves are in theindicad positions with power to the valve operators removed:Valve Nu ber Valve Function Valve Position864A a d B Supply from RWST to ECCS Open862A nd B RWST Supply to RHR pumps Open863 and B RHR Recirculation Closed/888A and B H.H.S.I.
to Hot Legs ClosedCV-758* RHR HX Outlet OpenTo permit temporary operation of these valves for surveillance or maintenance
: purposes, power may berestored to these valves for a period not to exceed 24 hours.b. .At lest .n.. per 31 days by.Verifying that the ECCS piping is full of water by venting the ECCS pump casings andS1 ,, accessible discharge piping,2) Verifying that each valve (manual, power-operated, or automatic) in the flow path that is notlocked, sealed, or otherwise secured in position, is in its correct position, and3) Verifying that each RHR Pump develops the indicated differential pressure applicable to theoperating conditions in accordance with Figure 3.5-1 when tested pursuant toSpecification 4.0.5.c. Aset -one-p 92 days- by:1) Verifying that each SI pump develops the indicated differential pressure applicable to theoperating conditions when tested pursuant to Specification 4.0.5.SI pump >_ 1083 psid at a metered flowrate
> 300 gpm (normal alignment or Unit 4 SI pumpsaligned to Unit 3 RWST), or> 1113 psid at a metered flowrate
> 280 gpm (Unit 3 SI pumps aligned to Unit 4RWST).*Air Supply to HCV-758 shall be verified shut off and sealed closed once per 31 days.TURKEY POINT -UNITS 3 & 43/4 5-5AMENDMENT NOS. 494-AND 8&5-r-EMERGENCY CORE COOLING SYSTEMSSURVEILLANCE REQUIREMENTS
: d. By a visual inspection which verifies that no loose debris (rags, trash, clothing, etc.) is present in thecontainment which could be transported to the containment sump and cause restriction of the pumpsuctions during LOCA conditions.
The visual inspection shall be performed:
: 1) For all accessible areas of the containment prior to establishing CONTAINMENT INTEGRITY, and2) At least once daily of the areas affected within containment by containment entry and during the 4,final entry when CONTAINMENT INTEGRITY is established.
: e. At least en per months by:1) Verifying automatic isolation and interlock action of the RHR system from the Reactor CoolantSystem by ensuring that with a simulated or actual Reactor Coolant System pressure signalgreater than or equal to 525 psig the interlocks cause the valves to automatically close andprevent the valves from being opened, andIsert 1 2) Verifying correct interlock action to ensure that the RWST is isolated from the RHR Systemduring RHR System operation and to ensure that the RHR System cannot be pressurized fromthe Reactor Coolant System unless the above RWST Isolation Valves are closed.3) A visual inspection of the containment sump and verifying that the suction inlets are notrestricted by debris and that the sump components (trash racks, screens,
.etc.) show noevidence of structural distress or abnormal corrosion.
: f. At least once per 18 months, during shutdown, by:1) Verifying that each automatic valve in the flow path actuates to its correct position on SafetyInjection actuation test signal, and2) Verifying that each of the following pumps start automatically upon receipt of a Safety Injection actuation test signal:a) Safety Injection pump, andb) RHR pump.TURKEY POINT -UNITS 3 & 43/4 5-7AMENDMENT NOS. 1-84-AND 1-8--
EMERGENCY CORE COOLING SYSTEMSSURVEILLANCE REQUIREMENTS
: g. By verifying the correct position of each electrical and/or mechanical position stop for the following ECCS throttle valves:1) Within 4 hours following completion of each valve stroking operation or maintenance on thevalve when the ECCS components are required to be OPERABLE, and2)-f. IrlT--.r I I~lf~l7RHR SRHR SValve IHCV-*-ys~temslumberInsert 1-758MOV-*-872 TURKEY POINT -UNITS 3 & 43/4 5-8AMENDMENT NOS. 43"8 AND 1" EMERGENCY CORE COOLING SYSTEMS3/4.5.4 REFUELING WATER STORAGE TANKLIMITING CONDITION FOR OPERATION 3.5.4 For single Unit operation, one refueling water storage tank (RWST) shall be OPERABLE or for dual Unitoperation two RWSTs shall be OPERABLE with:a. A minimum indicated borated water volume of 320,000 gallons per RWST,b. A boron concentration between 2400 ppm and 2600 ppm,c. A minimum solution temperature of 39&deg;F, andd. A maximum solution temperature of 100&deg;F.APPLICABILITY:
MODES 1, 2, 3, and 4.ACTION:With less than the required number of RWST(s) OPERABLE, restore the tank(s) to OPERABLE status within1 hour or be in at least HOT STANDBY within 6 hours and in COLD SHUTDOWN within the following 30 hours.SURVEILLANCE REQUIREMENTS 4.5.4 The required RWST(s) shall be demonstrated OPERABLE:
: a. 1 by:lInsert 1 1) Verifying the indicated borated water volume in the tank, and2) Verifying the boron concentration of the water.b. By verifying the RWST temperature is within limits whenever the outside air temperature is less than39&deg;F or greater than 1 00&deg;F at the following frequencies:
: 1) Within one hour upon the outside temperature exceeding its limit for consecutive 23 hours, and2) At least once per 24 hours while the outside temperature exceeds its limit.TURKEY POINT -UNITS 3 & 43/4 5-10AMENDMENT NOS. 249 AND 245 3/4.6 CONTAINMENT SYSTEMS3/4.6.1 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 1 hour or be in at leastHOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.SURVEILLANCE REQUIREMENTS 4.6.1.1 CONTAINMENT INTEGRITY shall be demonstrated:
by verifying that all penetrations**
not capable of being closed byPERABLE containment automatic isolation valves and required to be closed during accidentconditions are closed by valves, blind flanges, or deactivated automatic valves secured in theirclosed positions-,
: b. By verifying that each containment air lock is in compliance with the requirements ofSpecification 3.6.1.3.insert 1--7Exception may be taken under Administrative Controls for opening of valves and airlocks necessary toperform surveillance, testing requirements and/or corrective maintenance.
In addition, Specification 3.6.4shall be complied with.** Except valves, blind flanges, and deactivated automatic valves which are located inside the containment andare locked, sealed or otherwise secured in the closed position.
These penetrations shall be verified closedduring each COLD SHUTDOWN except that such verification need not be performed more often than onceper 92 days.TURKEY POINT -UNITS 3 & 43/4 6-1AMENDMENT NOS.t2-z-AND 2t9-CONTAINMENT SYSTEMSSURVEILLANCE REQUIREMENTS 4.6.1.3 Each containment air lock shall be demonstrated OPERABLE:
: a. Following each closing, at the frequency specified in the Containment Leakage Rate TestingProgram, by verifying that the seals have not been damaged and have seated properly byvacuum testing the volume between the door seals in accordance with approved plantprocedures.
: b. By conducting overall air lock leakage tests in accordance with the Containment Leakage RateTesting Program.c. At leoat once per 24 monthls by verifying that only one door in each air lock can be opened at atime.Insert 1TURKEY POINT -UNITS 3 & 43/4 6-5AMENDMENT NOS. 24-3 AND 2e7 CONTAINMENT SYSTEMSINTERNAL PRESSURELIMITING CONDITION FOR OPERATION 3.6.1.4 Primary containment internal pressure shall be maintained between -2 and +1 psig.APPLICABILITY:
MODES 1, 2, 3, and 4.ACTION:With the containment internal pressure outside of the limits above, restore the internal pressure to within the limitswithin 1 hour or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within thefollowing 30 hours.SURVEILLANCE REQUIREMENTS 4.6.1.4 The primary containment internal pressure shall be determined to be within the limits at least -enee peInsert 1TURKEY POINT -UNITS 3 & 43/4 6-6AMENDMENT NOS. 249-AND 245 CONTAINMENT SYSTEMSAIR TEMPERATURE LIMITING CONDITION FOR OPERATION 3.6.1.5 Primary containment average air temperature shall not exceed 1250F and shall not exceed 120'F bymore than 336 equivalent hours* during a calendar year.APPLICABILITY:
MODES 1, 2, 3, and 4.ACTION:With the containment average air temperature greater than 1250F or greater than 120OF for more than336 equivalent hours* during a calendar year, reduce the average air temperature to within the applicable limitwithin 8 hours, or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within thefollowing 30 hours.SURVEILLANCE REQUIREMENTS 4.6.1.5 The primary containment average air temperature shall be the arithmetical average of the temperatures atthe following locations and shall be determined at !east once Per ,:2 hou-rs:Approximate Locationa. 00 Azimuth 58 feet elevation Insert 1D::. 12 58 Teet elevation
: c. 2400 Azimuth 58 feet elevation
* Equivalent hours are determined from actual hours using the time-temperature relationships that support theenvironmental qualification requirements of 10 CFR 50.49.TURKEY POINT -UNITS 3 & 43/4 6-7AMENDMENT NOS. +-H AND-4-3 CONTAINMENT SYSTEMSCONTAINMENT VENTILATION SYSTEMLIMITING CONDITION FOR OPERATION 3.6.1.7 Each containment purge supply and exhaust isolation valve shall be OPERABLE and:a. The containment purge supply and exhaust isolation valves shall be sealed closed to themaximum extent practicable but may be open for purge system operation for pressure
: control, forenvironmental conditions
: control, for ALARA and respirable air quality considerations forpersonnel entry and for surveillance tests that require the valve to be open.b. The purge supply and exhaust isolation valves shall not be opened wider than 33 or 30 degrees,respectively (90 degrees is fully open).APPLICABILITY:
MODES 1, 2, 3, AND 4.ACTION:a. With a containment purge supply and/or exhaust isolation valve(s) open for reasons other thangiven in 3.6.1.7.a above, close the open valve(s) or isolate the penetration(s) within 4 hours,otherwise be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN withinthe following 30 hours.b. With a containment purge supply and/or exhaust isolation valve(s) having a measured leakagerate exceeding the limits of Specification 4.6.1.7.2, restore the inoperable valve(s) to OPERABLEstatus or isolate the penetrations such that the measured leakage rate does not exceed the limitsof Specification 4.6.1.7.2 within 24 hours, otherwise be in at least HOT STANDBY within the next6 hours and in COLD SHUTDOWN within the following 30 hours.SURVEILLANCE REQUIREMENTS 4.6.1.7.1 Each containment purge supply and exhaust isolation valve shall be verified to be sealed closed oropen in accordance with Specification 3.6.1.7.a at l' F... cr ,31 days.4.6.1.7.2 At 'east enee P.r FAA~ths, each containm nt purge supply and exhaust isolation valve shall bedemonstrated OPERABL verifying that the me ured leakage rate is less than or equal to 0.05 La whenpressurized to Pa.4.6.1.7.3 At least cnr, pr 18 mznths, the c anical stop on each containment purge supply and exhaustisolation valve shall b rified to be in place a d that the valves will open no more than 33 or 30 degrees,respectively.
TURKEY POINT -UNITS 3 & 43/46-11 AMENDMENT NOS. 4-37 AND 432-CONTAINMENT SYSTEMS3/4.6.2 DEPRESSURIZATION AND COOLING SYSTEMSCONTAINMENT SPRAY SYSTEMLIMITING CONDITION FOR OPERATION 3.6.2.1 Two independent Containment Spray Systems shall be OPERABLE with each Spray System capable oftaking suction from the RWST and manually transferring suction to the containment sump via the RHR System.APPLICABILITY:
MODES 1, 2, 3, and 4.ACTION:a. With one Containment Spray System inoperable restore the inoperable Spray System toOPERABLE status within 72 hours or be in at least HOT STANDBY within the next 6 hours and inCOLD SHUTDOWN within the following 30 hours.b. With two Containment Spray Systems inoperable restore at least one Spray System toOPERABLE status within 1 hour or be in at least HOT STANDBY within the next 6 hours and inCOLD SHUTDOWN within the following 30 hours. Restore both Spray Systems to OPERABLEstatus within 72 hours of initial loss or be in at least HOT STANDBY within the next 6 hours and inCOLD SHUTDOWN within the following 30 hours.SURVEILLANCE REQUIREMENTS 4.6.2.1 Each Containment Spray System shall be demonstrated OPERABLE:
: a. .t lent once per 31 day-s by verifying that each valve (manual, power-operated, or automatic) inthe fl path that is not locked, sealed, or otherwise secured in position, is in its correct positionan'that power is available to flow path components that require power for operation;
: b. y verifying that on recirculation flow, each pump develops the indicated differential
: pressure, when tested pursuant to Specification 4.0.5:Containment Spray Pump >241.6 psid while aligned in recirculation mode.IInsert 1TURKEY POINT -UNITS 3 & 43/4 6-12AMENDMENT NOS. +-37-AND 1
CONTAINMENT SYSTEMSSURVEILLANCE REOUIREMENTS
(.Continued)
: c. At Ie once p-r- 18r months during shutdown by:Verifying that each automatic valve in the flow path actuates to its correct position on acontainment spray actuation test signal, andilnsert 1 2) Verifying that each spray pump starts automatically on a containment spray actuation testsignal. The manual isolation valves in the spray lines at the containment shall be lockedclosed for the performance of these tests.d.st oe per !0 years by performing an air or smoke flow test through each spray headerand verifying each spray nozzle is unobstructed.
TURKEY POINT -UNITS 3 & 43/46-13 AMENDMENT NOS. 465 AND 4-59 CONTAINMENT SYSTEMSEMERGENCY CONTAINMENT COOLING SYSTEMLIMITING CONDITION FOR OPERATION 3.6.2.2 Three emergency containment cooling units shall be OPERABLE.
APPLICABILITY:
MODES 1, 2, 3, and 4.a. With one of the above required emergency containment cooling units inoperable restore theinoperable cooling unit to OPERABLE status within 72 hours or be in at least HOT STANDBYwithin the next 6 hours and in COLD SHUTDOWN within the following 30 hours.b. With two or more of the above required emergency containment cooling units inoperable, restoreat least two cooling units to OPERABLE status within 1 hour or be in at least HOT STANDBYwithin the next 6 hours and in COLD SHUTDOWN within the following 30 hours. Restore all of theabove required cooling units to OPERABLE status within 72 hours of initial loss or be in at leastHOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours.SURVEILLANCE REQUIREMENTS 4.6.2.2 Each emergency containment cooling unit shall be demonstrated OPERABLE:
: a. At least e,,e p...31 days by starting each cooler unit from the control room and verifying thate unit motor reaches the nominal operating current for the test conditions and operates for atast 15 minutes./b., At least enee pr 1 8 moneth by:1) Verifying that two emergency containment cooling units start automatically on a safety.sert 1 injection (SI) test signal, and2) Verifying a cooling water flow rate of greater than or equal to 2000 gpm to each cooler.TURKEY POINT -UNITS 3 & 43/4 6-!4AMENDMENT NOS. 4-94 AND +&&
CONTAINMENT SYSTEMS3/4.6.2.3 RECIRCULATION pH CONTROL SYSTEMLIMITING CONDITION FOR OPERATION 3.6.2.3 The Recirculation pH Control System shall be OPERABLE.
APPLICABILITY:
MODES 1, 2, 3, and 4.ACTION:With the Recirculation pH Control System inoperable, restore the buffering agent to OPERABLE status within 72hours or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the next 72hours.SURVEILLANCE REQUIREMENTS 4.6.2.3 The Recirculation pH Control System shall be demonstrated OPERABLE:
: a. At least zene per 18 &deg;mcnths by:1. Verifying that the buffering agent baskets are in place and intact;nert 2. Collectively contain > 7500 pounds (154 cubic feet) of sodium tetraborate decahydrate, or equivalent.
TURKEY POINT -UNITS 3 & 43/4 6-15AMENDMENT NOS. 2 AND 253 CONTAINMENT SYSTEMSSURVEILLANCE REQUIREMEN-(QContinued) 4.6.4.2 Each isolation ve shall be demonstrated OPERABLE during the COLD SHUTDOWN or REFUELING MODE at east oARco 'Re '.. mem4ts by:a. Verifying that on a Phase "A" Isolation test signal, each Phase "A" isolation valve actuates to itsisolation position;
: b. Verifying that on a Phase "B" Isolation test signal, each Phase "B" isolation valve actuates to itsisolation position; andc. Verifying that on a Containment Ventilation Isolation test signal, each purge, exhaust andinstrument air bleed valve actuates to its isolation position.
4.6.4.3 The isolation time of each power-operated or automatic valve shall be determined to be within its limitwhen tested pursuant to Specification 4.0.5.TURKEY POINT -UNITS 3 & 43/4 6-18AMENDMENT NOS. 1-3 AND PLANT SYSTEMSAUXILIARY FEEDWATER SYSTEMLIMITING CONDITION FOR OPERATION 3.7.1.2 Two independent auxiliary feedwater trains including 3 pumps as specified in Table 3.7-3 and associated flowpaths shall be OPERABLE.
APPLICA84-L-T:
MODES 1, 2 and 3ACTION: APPLICABILITY
: 1) With one of the two required independent auxiliary feedwater trains inoperable, either restore theinoperable train to an OPERABLE status within 72. hours, or place the affected unit(s) in at leastHOT STANDBY within the next 6 hours* and in HOT SHUTDOWN within the following 6 hours.2) With both required auxiliary feedwater trains inoperable, within 2 hours either restore both trainsto an OPERABLE status, or restore one train to an OPERABLE status and follow ACTIONstatement 1 above for the other train. If neither train can be restored to an OPERABLE statuswithin 2 hours, verify the OPERABILITY of both standby feed-water pumps and place the affectedunit(s) in at least HOT STANDBY within the next 6 hours* and in HOT SHUTDOWN within thefollowing 6 hours. Otherwise, initiate corrective action to restore at least one auxiliary feedwater train to an OPERABLE status as soon as possible and follow ACTION statement 1 above for theother train.3) With a single auxiliary feedwater pump inoperable, within 4 hours, verify OPERABILITY of twoindependent auxiliary feedwater trains, or follow ACTION statements 1 or 2 above as applicable.
Upon verification of the OPERABILITY of two independent auxiliary feedwater trains, restore theinoperable auxiliary feedwater pump to an OPERABLE status within 30 days, or place theoperating unit(s) in at least HOT STANDBY within 6 hours* and in HOT SHUTDOWN within thefollowing 6 hours. The provisions of Specification 3.0.4 are not applicable during the 30 dayperiod for the inoperable auxiliary feedwater pump.SURVEILLANCE REQUIREMENTS 4.7.1.2.1 The required independent auxiliary feedwater trains shall be demonstrated OPERABLE:
: a. ... ....... .. days on a STAGGERED TEST BASIS by:Verifying by control panel indication and visual observation of equipment that each steamturbine-driven pump operates for 15 minutes or greater and develops a flow of greaterthan orLInsert 1*If this ACTION applies to both units simultaneously, be in at least HOT STANDBY within the next 12 hours andin HOT SHUTDOWN within the following 6 hours.TURKEY POINT -UNITS 3 & 43/4 7-3AMENDMENT NOS. 447 AND +3-PLANT SYSTEMSAUXILIARY FEEDWATER SYSTEMSURVEILLANCE REQUIREMENTS (Continued) equal to 373 gpm to the entrance of the steam generators.
The provisions ofSpecification 4.0.4 are not applicable for entry into MODES 2 and 3;2) Verifying by control panel indication and visual observation of equipment that the auxiliary feedwater discharge valves and the steam supply and turbine pressure valves operate asrequired to deliver the required flow during the pump performance test above;3) Verifying that each non-automatic valve in the flow path that is not locked, sealed, orotherwise secured in position is in its correct position; and4) Verifying that power is available to those components which require power for flow pathoperability.
b .e &deg; ..'-^ by:1) Verifying that each automatic valve in the flow path actuates to its correct position uponInsert 1 Jreceipt of each Auxiliary Feedwater Actuation test signal, and2) Verifying that each auxiliary feedwater pump receives a start signal as designedautomatically upon receipt of each Auxiliary Feedwater Actuation test signal.4.7.1.2.2 An auxiliary feedwater flow path to each steam generator shall be demonstrated OPERABLE following each COLD SHUTDOWN of greater than 30 days prior to entering MODE 1 by verifying normal flow to eachsteam generator.
TURKEY POINT -UNITS 3 & 43/4 7-4AMENDMENT NOS. +57 AND 4-32--
PLANT SYSTEMSSURVEILLANCE REQUIREMENTS (Continued) 4.7.1,3 The condensate storage tank (CST) system shall be demonstrated OPERABLE at lcast ,eon per12 196HtFeby verifying the indicated water volume is within its limit when the tank is the supply source for theauxiliary feedwater pumpInoser 1TURKEY POINT -UNITS 3 & 43/4 7-7AMENDMENT NOS. "94 AND -8&
PLANT SYSTEMSSPECIFIC ACTIVITYNo change this page,for information onlyLIMITING CONDITION FOR OPERATION 3.7.1.4 The specific activity of the Secondary Coolant System shall be less than or equal to 0.10 microCurie/gram DOSE EQUIVALENT 1-131.APPLICABILITY:
MODES 1, 2, 3, and 4.ACTION:With the specific activity of the Secondary Coolant System greater than 0.10 microCurie/gram DOSEEQUIVALENT 1-131, be in at least HOT STANDBY within 6 hours and in COLD SHUTDOWN within the following 30 hours.SURVEILLANCE REQUIREMENTS 4.7.1.4 The specific activity of the Secondary Coolant System shall be determined to be within the limit byperformance of the sampling and analysis program of Table 4.7-1.TURKEY POINT -UNITS 3 & 43/4 7-8AMENDMENT NOS. 137 AND 132 TABLE 4.7-1SECONDARY COOLANT SYSTEM SPECIFIC ACTIVITYSAMPLE AND ANALYSIS PROGRAMTYPE OF MEASUREMENT AND ANALYSISSAMPLE AND ANALYSISFREQUENCY
: 1. Gross Radioactivity Determination
: 2. Isotopic Analysis for DOSEEQUIVALENT 1-131 Concentration At 'east ema) Once per 31 days, when-ever the gross radio-activity determination indicates concentrations greater than 10% of theallowable limit forradioiodines.
b) Once per 6 months, when-ever the gross radio-activity determination indicates concentrations less than or equal to 10%of the allowable limitfor radioiodines.
TURKEY POINT -UNITS 3 & 43/47-9AMENDMENT NOS. 1-8;7 AND 2 PLANT SYSTEMSSTANDBY FEEDWATER SYSTEMLIMITING CONDITION FOR OPERATION 3.7.1.6 Two Standby Steam Generator Feedwater Pumps shall be OPERABLE*
and at least 145,000 gallons of,/water (indicated volume),
shall be in the Demineralized Water Storage Tank.** I'"APPLICABILITY:
MODES 1, 2 and 3ACTION:a. With one Standby Steam Generator Feedwater Pump inoperable, restore the inoperable pump toavailable status within 30 days or submit a SPECIAL REPORT per 3.7.1.6d.
: b. With both Standby Steam Generator Feedwater Pumps inoperable, restore at least one pump toOPERABLE status within 24 hours, or:1. Notify the NRC within the following 4 hours, and provide cause for the inoperability and plans torestore pump(s) to OPERABLE status and,2. Submit a SPECIAL REPORT per 3.7.1.6d.
: c. With less than 145,000 gallons of water indicated in the Demineralized Water Storage Tank restore theavailable volume to at least 145,000 gallons indicated within 24 hours or submit a SPECIAL REPORT pert -3.7.1.6d.
: d. If a SPECIAL REPORT is required per the above specifications submit a report describing the cause ofthe inoperability, action taken and a schedule for restoration within 30 days in accordance with 6.9.2.SURVEILLANCE REQUIREMENTS 4.7.1.6.1 The Demineralized Water Storage tank water volume shall be'determined to be within limits atleeastonce per 21' hcurasr-4.7.1.6.2 A-es verify the standby feedwater pumps are OPERABLE by testing in recirculation on aSTAGGERED TEST BASIS.Insert 4.7.1.6.3 At 'east an verify operability of the respective standby steam generator feedwater pump by starting each pump and providing feedwater to the steam generators.
*These pumps do not require plant safety related emergency power sources for operability and the flowpath isnormally isolated.
**The Demineralized Water Storage Tank is non-safety grade.TURKEY POINT -UNITS 3 & 43/4 7-11AMENDMENT NOS. 24,9-AND-245-PLANT SYSTEMSSURVEILLANCE REQUIREMENTS (Continued) 4.7.1.6.4 The diesel engine for the diesel-driven Standby Steam Generator Feedwater Pump shall bedemonstrated OPERABLE:
: a. s-- one evr 34-da, by testing with the associated standby steam generator feedwater Insert 1 __ p in recirculation.
: b. .-.. e ........
,by subjecting the diesel to an inspection in accordance withprocedures prepared in conjunction with its manufacturer's recommendations for the class ofservice.TURKEY POINT -UNITS 3 & 43/4 7-11 aAMENDMENT NOS. 1s-4-AND 4-S&
PLANT SYSTEMS3/4.7.1.7 FEEDWATER ISOLATION LIMITING CONDITION FOR OPERATION 3.7.1.7 Six Feedwater Control Valves (FCVs) both main and bypass and six Feedwater Isolation Valves (FIVs)both main and bypass shall be OPERABLE.*
APPLICABILITY:
MODES 1, 2 and 3**ACTION:a. With one or more FCVs inoperable, restore operability, or close or isolate the inoperable FCVs within 72hours and verify that the inoperable valve(s) is closed or isolated at least once per 7 days or be in HOTSTANDBY within the next 6 hours and in HOT SHUTDOWN within the following 6 hours.b. With one or more FIVs inoperable, restore operability, or close or isolate the inoperable FIV(s) within 72hours and verify that the inoperable valve(s) is closed or isolated at least once per 7 days or be in HOTSTANDBY within the next 6 hours and in HOT SHUTDOWN within the following 6 hours.c. With one or more bypass valves in different steam generator flow paths inoperable, restore operability, orclose or isolate the inoperable bypass valve(s) within 72 hours and verify that the inoperable valve(s) isclosed or isolated at least once per 7 days or be in HOT STANDBY within the next 6 hours and in HOTSHUTDOWN within the following 6 hours.d. With two valves in the same steam generator flow paths inoperable, restore operability, or isolate theaffected flowpath within 8 hours or be in HOT STANDBY within the next 6 hours and in HOTSHUTDOWN within the following 6 hours..SURVEILLANCE REQUIREMENTS 4.7.1.7 Each FCV, FIV and bypass valve shall be demonstrated OPERABLE:
: a. At least ever'' 18 months by:1) Verifying that each FCV, FIV and bypass valve actuates to the isolation position on anInsert 1 actual or simulated actuation signal.b. In accordance with the Inservice Testing Program by:1) Verifying that each FCV, FIV and bypass valve isolation time is within limits.*Separate Condition entry is allowed for each valve.**The provisions of specification 3.0.4 and 4.0.4 are not applicable.
///1TURKEY POINT -UNITS 3 & 43/4 7-11 bAMENDMENT NOS.-24" AND 24-a PLANT SYSTEMS3/4,7.2 COMPONENT COOLING WATER SYSTEMLIMITING CONDITION FOR OPERATION 3.7,2 The Component Cooling Water System (CCW) shall be OPERABLE with:a. Three CCW pumps, andb. Two CCW heat exchangers.
APPLICABILITY:
MODES 1, 2, 3, and 4.ACTION:a. With only two CCW pumps with independent power supplies
: OPERABLE, restore the inoperable CCW pump to OPERABLE status within 30 days or be in HOT STANDBY within the next 6 hoursand in COLD SHUTDOWN within the following 30 hours. The provisions of Specification 3.0.4 arenot applicable.
: b. With only one CCW pump OPERABLE or with two CCW pumps OPERABLE but not fromindependent power supplies, restore two pumps from independent power supplies to OPERABLEstatus within 72 hours or be in HOT STANDBY within the next 6 hours and in COLD SHUTDOWNwithin the following 30 hours.c. With less than two CCW heat exchangers
: OPERABLE, restore two heat exchangers toOPERABLE status within 1 hour or be in HOT STANDBY within the next 6 hours and in COLDSHUTDOWN within the following 30 hours.SURVEILLANCE REQUIREMENTS 4.7,2 The Component Cooling Water System (CCW) shall be demonstrated OPERABLE:
: a. At least .... pr 1 hors, by verifying that two heat exchangers and one pump are capable ofre ving design basis heat loads.Insert 1TURKEY POINT -UNITS 3 & 43/4 7-12AMENDMENT NOS. 4-37-AND
+32-SURVEILLANCE REQUIREMENTS (Continued)
: b. At"4pa.t
...... pe. 31 by: (1) verifying that each valve (manual, power-operated, orAt'rmatic) servicing safety-related equipment that is not locked, sealed, or otherwise secured inposition is in its correct position and (2) verifying by a performance test the heat exchanger Insert 1 surveillance curves.*c. At ',-st ,nee per 18 menth during shutdown, by verifying that:1) Each automatic valve servicing safety-related equipment actuates to its correct positionon a Sl test signal, and2) Each Component Cooling Water System pump starts automatically on a SI test signal.3) Interlocks required for CCW operability are OPERABLE.
*Technical specification 4.7.2.b(2) is not applicable for entry into MODE 4 or MODE 3, provided that:1) Surveillance 4.7.2.b(2) is performed no later than 72 hours after reaching a Reactor CoolantSystem Tavg of 5470F, and2) MODE 2 shall not be entered prior to satisfactory performance of this surveillance.
TURKEY POINT -UNITS 3 & 43/4 7-13AMENDMENT NOS. 446 AND 44-3 PLANT SYSTEMS3/4.7.3 INTAKE COOLING WATER SYSTEMLIMITING CONDITION FOR OPERATION 3.7.3 The Intake Cooling Water System (ICW) shall be OPERABLE with:a. Three ICW pumps, andb. Two ICW headers.APPLICABILITY:
MODES 1, 2, 3, and 4.ACTION:a. With only two ICW pumps with independent power supplies
: OPERABLE, restore the inoperable ICW pump to OPERABLE status within 14 days or be in HOT STANDBY within the next 6 hoursand in COLD SHUTDOWN within the following 30 hours. The provisions of Specification 3.0.4 arenot applicable.
: b. With only one ICW pump OPERABLE or with two ICW pumps OPERABLE but not fromindependent power supplies, restore two pumps from independent power supplies to OPERABLEstatus within 72 hours or be in HOT STANDBY within the next 6 hours and in COLD SHUTDOWNwithin the following 30 hours.c. With only one ICW header OPERABLE, restore two headers to OPERABLE status within72 hours or be in HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within thefollowing 30 hours.SURVEILLANCE REQUIREMENTS 4.7.3 The Intake Cooling Water System (ICW) shall be demonstrated OPERABLE:
: a. --- pa- "3 dy by verifying that each valve (manual, power-operated, or automatic) e.icing safety-related equipment that is not locked, sealed, or otherwise secured in position is inInsert 1 its correct position; andb. uring shutdown, by verifying that:1) Each automatic valve servicing safety-related equipment actuates to its correct positionon a SI test signal, and2) Each Intake Cooling Water System pump starts automatically on a SI test signal.3) Interlocks required for system operability are OPERABLE.
TURKEY POINT -UNITS 3 & 43/4 7-14AMENDMENT NOS. 2-AND 2
PLANT SYSTEMS3/4.7.4 ULTIMATE HEAT SINKLIMITING CONDITION FOR OPERATION 3.7.4 The ultimate heat sink shall be OPERABLE with an average supply water temperature less than or equal to100&deg; F.APPLICABILITY:
MODES 1. 2, 3. and 4.ACTION:With the requirements of the above specification not satisfied, be in at least HOT STANDBY within 12 hours andIn COLD SHUTDOWN within the following 30 hours. This ACTION shall be applicable to both unitssimultaneously.
SURVEILLANCE REQUIREMENTS 4.7.4 The ultimate heat sink shall be determined OPERABLE at least once per 24 ho'-rs by verifying the averagesupply water temperature*
to be within ii*Insert 1 t*Portable monitors may be used to measure the temperature.
TURKEY POINT -UNITS 3 & 43/4 7-15AMENDMENT NOS. 2e&AND +94-PLANT SYSTEMS3/4.7.5 CONTROL ROOM EMERGENCY VENTILATION SYSTEMLIMITING CONDITION FOR OPERATION (continued)
: b. With the Control Room Emergency Ventilation System inoperable due to an inoperable CREboundary, immediately suspend all movement of irradiated fuel in the spent fuel pool, andimmediately initiate action to implement mitigating
: actions, and within 24 hours, verify mitigating actions ensure CRE occupant radiological and chemical hazards will not exceed limits, and CREoccupants are protected from smoke hazards, and restore CRE boundary to OPERABLE statuswithin 90 days, or:1) With the requirements not met, be in at least HOT STANDBY within the next 6 hours andin COLD SHUTDOWN within the following 30 hours.2) If this ACTION applies to both units simultaneously, be in HOT STANDBY within 12hours and in COLD SHUTDOWN within the following 30 hours.MODES 5 and 6:c. With the Control Room Emergency Ventilation System inoperable++,
immediately suspend alloperations involving CORE ALTERATIONS, movement of irradiated fuel in the spent fuel pool, orpositive reactivity changes.
This ACTION shall apply to both units simultaneously.
SURVEILLANCE REQUIREMENTS 4.7.5 The Control Room Emergency Ventilation System shall be demonstrated OPERABLE:
: a. A once per 12 hours by verifying that the control room air temperature is less than or equal tob. , ,-+/- o , by initiating, from the control room, flow through the HEPA filters andInsert 1 charcoal adsorbers and verifying that the system operates for at least 15 minutes***;
c .. or (1) after 720 hours of system operation, or (2) after any structural maintenance on the HEPA filter or charcoal adsorber
: housings, or (3) following exposure of thefilters to effluents from painting, fire, or chemical release in any ventilation zone communicating withthe system that may have an adverse effect on the functional capability of the system, or (4) aftercomplete or partial replacement of a filter bank by:++ If action per ACTIONS a.4, a.6, a.7, a.8, or a.9 is taken that permits indefinite operation and the system isplaced in recirculation mode, then CORE ALTERATIONS, movement of irradiated fuel in the spent fuel pool, andpositive reactivity changes may resume.***As the mitigation actions of TS 3.7.5 Action a.5 may include the use of the compensatory filtration unit, the unitshall meet the surveillance requirements of TS 4.7.5.b, by manual initiation from outside the control room and TS4.7.5.c and d.TURKEY POINT -UNITS 3 & 43/4 7-16bAMENDMENT NOS. 25--AND 240 PLANT SYSTEMSSURVEILLANCE REQUIREMENTS (Continued)
: 1) Verifying that the air cleanup system satisfies the in-place penetration and bypassleakage testing acceptance criteria of greater than or equal to 99% DOP andhalogenated hydrocarbon removal at a system flow rate of 1000 cfm +/-1 0%***.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, and analyzed per ASTM D3803 -1989 at 300C and95% relative
: humidity, meets the methyl iodide penetration criteria of less than 2.5% orthe charcoal be replaced with charcoal that meets or exceeds the stated performance requirement***,
and3) Verifying by a visual inspection the absence of foreign materials and gasketdeterioration***.
d.1 At eoast eree per 12 months by verifying that the pressure drop across the combined HEPA filterscharcoal adsorber banks is less than 6 inches Water Gauge while operating the system at aflow rate of 1000 cfm +/-1 0%***; f1Nd.2 On STAGGERED TEST BASIS evepy 36 miniths , test the supply fans (trains A and B) and measurej, CRE pressure relative to external areas adjacent to the CRE boundary.
4KlInsert 1 -_ .,.... t once p, ............
by .'' t on a Containment Phase A" Isolation test signal thesystem matically switches into the recirculation mode of operation, f At least once erability of the kitchen and toilet area exhaust dampers,andg. By performing required CRE unfiltered air inleakage testing in accordance with the Control RoomEnvelope Habitability Program.***As the mitigation actions of TS 3.7.5 Action a.5 may include the use of the compensatory filtration unit, the unitshall meet the surveillance requirements of TS 4.7.5.b, by manual initiation from outside the control room and TS4.7.5.c and d.TURKEY POINT -UNITS 3 & 43/4 7-17AMENDMENT NOS. 24f--AND 244 PLANT SYSTEMS3/4.7.7 SEALED SOURCE CONTAMINATION LIMITING CONDITION FOR OPERATION 3.7.7 Each sealed source containing radioactive material either in excess of 100 microCuries of beta and/orgamma emitting material or 5 microCuries of alpha emitting material shall be free of greater than or equal to 0.005microCurie of removable contamination.
APPLICABILITY:
At all times.ACTION:a. With a sealed source having removable contamination in excess of the above limits, immediately withdraw the sealed source from use and either:1. Decontaminate and repair the sealed source, or2. Dispose of the sealed source in accordance with Commission Regulations.
: b. The provisions of Specification 3.0.3 are not applicable.
SURVEILLANCE REQUIREMENTS 4.7.7.1 Test Requirements
-Each sealed source shall be tested for leakage and/or contamination by:a. The licensee, orb. Other persons specifically authorized by the Commission or an Agreement State.The test method shall have a detection sensitivity of at least 0.005 microCurie per test sample.4.7.7.2 Test Frequencies
-Each category of sealed sources (excluding startup sources and fission detectors previously subjected to core flux) shall be tested at the frequency described below.a. Sources in use -At 'east en.. per 6 ...nth. for all sealed sources containing radioactive materials:
: 1) With a half-life greater than 30 s (excluding Hydrogen 3), and2) In any form other than gas.TURKEY POINT -UNITS 3 & 43/4 7-22AMENDMENT NOS. 4G-7&#xfd;-AND
+a2-ELECTRICAL POWER SYSTEMSIn~sert 1ISU RVEILLANCE REQUIREMENTS
\4.8.1.1.1 Each of the above required sta up transformers and their associated circuits shall be:a. Determined OPERABLE
-t .s c 7 days by verifying correct breaker alignments, indicated power availability, andb. Demonstrated OPERABLE at 'Part on.c per 418 month& while shutting down, by transferring manually unit power supply from the auxiliary transformer to the startup transformer.
TURKEY POINT -UNITS 3 & 43/4 8-4aAMENDMENT NOS. 2e-2. AND 4 ELECTRICAL POWER SYSTEMSSURVEILLANCE REQUIREMENTS (Continued) 4.8.1.1.2 Each diesel generator shall be demonstrated OPERABLE*:
: a. ,- ....... per days on a STAGGERED TEST BASIS by:1 Verifying the fuel volume in the day and skid-mounted fuel tanks (Unit 4-day tank only),2) Verifying the fuel volume in the fuel storage tank,3) Verifying the lubricating oil inventory in storage,4) Verifying the diesel starts and accelerates to reach a generator voltage and frequency of3950-4350 volts and 60 + 0.6 Hz. Once per 184 days, these conditions shall be reachedwithin 15 seconds after the start signal fro m normal conditions.
For all other starts,warmup procedures, such as idling and gradual acceleration as recommended by themanufacturer may be used. The diesel generator shall be started for this test by usingone of the following signals:a) Manual, orb) Simulated loss-of-offsite power by itself, orc) Simulated Ioss-of-offsite power in conjunction with an ESF Actuation test signal,ord) An ESF Actuation test signal by itself.5) Verifying the generator is synchronized, loaded**
to 2300 -2500 kW (Unit 3), 2650-2850 kW (Unit 4)***, operates at this loaded condition for at least 60 minutes and for Unit 3until automatic transfer of fuel from the day tank to the skid mounted tank isdemonstrated, and the cooling system is demonstrated OPERABLE.
: 6) Verifying the diesel generator is aligned to provide standby power to the associated emergency busses.* All diesel generator starts for the purpose of these surveillances may be proceeded by a prelube period asrecommended by the manufacturer.
** May include gradual loading as recommended by the manufacturer so that the mechanical stress and wear onthe diesel engine is minimized.
***Momentary transients outside these load bands do not invalidate this test.TURKEY POINT -UNITS 3 & 43/4 8-5AMENDMENT NOS. 249 AND 245 Fl1 FC'_TPIC'A1 PCWXA)FP
_qV~TPftA5q SURVEILLANCE REQUIREMENTS (Continued)
: b. Demonstrating at least once pzr 92 days that a fuel trans pump starts automatically andtransfers fuel from the storage system to the day tank,c. At least an,, per 31 day, and after each operation of the diesel where the period of operation s greater than or equal to 1 hour by checking for and removing accumulated water from theday and skid-mounted fuel tanks (Unit 4-day tank only);d At ',et ,-0, per 31 days by checking for and removing accumulated water from the fuel oilst ge tanks;By verifying fuel oil properties of new fuel oil are tested in accordance with, and maintained withinthe limits of, the Diesel Fuel Oil Testing Program.rt 1_ By verifying fuel oil properties of stored fuel oil are tested in accordance with, and maintained within the limits of, the Diesel Fuel Oil Testing Program.g. At least cee per 18 mo.tl..s, during shutdown (applicable to only the two diesel generators associated with the unit):1) Deleted2)* Verifying the generator capability to reject a load of greater than or equal to 380 kw whilemaintaining voltage at 3950-4350 volts and frequency at 60 +/- 0.6 Hz;3)* Verifying the generator capability to reject a load of greater than or equal to 2500 kW(Unit 3), 2874 kW (Unit 4) without tripping.
The generator voltage shall return to less thanor equal to 4784 volts within 2 seconds following the load rejection;
: 4) Simulating a loss-of-offsite power by itself, and:a) Verifying deenergization of the emergency busses and load shedding from theemergency busses, andb. Verifying the diesel starts on the auto-start signal, energizes the emergency busses with any permanently
* For the purpose of this test, warmup procedures, such as idling, gradual acceleration, and gradual loading asrecommended by the manufacturer may be used.TURKEY POINT -UNITS 3 & 43/4 8-6AMENDMENT NOS. 24.-AND 245-No change this page,for information onlyELECTRICAL POWER SYSTEMSSURVEILLANCE REQUIREMENTS (Continued) connected loads within 15 seconds, energizes the auto-connected shutdown loads-through the load sequencer and operates for greater than or equal to 5 minutes while itsgenerator is loaded with the auto-connected shutdown loads. After automatic loadsequencing, the steady-state voltage and frequency of the emergency busses shall bemaintained at 3950-4350 volts and 60 +/- 0.6 Hz during this test.5) Verifying that on an ESF Actuation test signal, without Ioss-of-offsite power, the dieselgenerator starts on the auto-start signal and operates on standby for greater than orequal to 5 minutes.
The generator voltage and frequency shall be 3950-4350 volts and60 +/- 0.6 Hz within 15 seconds after the auto-start signal; the steady-state generator voltage and frequency shall be maintained within these limits during this test;6) Simulating a loss-of-offsite power in conjunction with an ESF Actuation test signal, and:a) Verifying deenergization of the emergency busses and load shedding from theemergency busses;b) Verifying the diesel starts on the auto-start signal; energizes the emergency busses with any permanently connected loads within 15 seconds, energizes theauto-connected emergency (accident) loads through the load sequencer andoperates for greater than or equal to 5 minutes while its generator is loaded withthe emergency loads. After automatic load sequencing, the steady-state voltageand frequency of the emergency busses shall be maintained at 3950-4350 voltsand 60,+/- 0.6 Hz during this test; andc) Verifying that diesel generator trips that are made operable during the test modeof diesel operation are inoperable.
7)* # Verifying the diesel generator operates for at least 24 hours. During the first 2 hours ofthis test, the diesel generator shall be loaded to 2550-2750 kW (Unit 3), 2950-3150 kW(Unit 4)** and during the remaining 22 hours of this test, the diesel generator shall beloaded to 2300-2500 kW (Unit 3), 2650-2850 kW (Unit 4)**. The generator voltage andfrequency shall be 3950-4350 volts and 60 +/- 0.6 Hz within 15 seconds after the startsignal; the steady-state generator voltage and frequency
* For the purpose of this test, warmup procedures, such as idling, gradual acceleration, and gradual loading asrecommended by the manufacturer may be used.** Momentary transients outside these load bands do not invalidate this test.# This test may be performed during POWER OPERATION TURKEY POINT -UNITS 3 & 4.3148-7AMENDMENT NOS. 249 AND 245 No change this page,for information onlyELECTRICAL POWER SYSTEMSSURVEILLANCE REQUIREMENTS (Continued) shall be maintained within these limits during this test. Within 5 minutes after completing this 24-hour test, verify the diesel starts and accelerates to reach a generator voltage andfrequency of 3950-4350 volts and 60 +/- 0.6 Hz within 15 seconds after the start signal.**
: 8) Verifying that the auto-connected loads to each diesel generator do not exceed 2500 kW(Unit 3), 2874 kW (Unit 4);9) Verifying the diesel generator's capability to:a) Synchronize with the offsite power source while the generator is loaded with itsemergency loads upon a simulated restoration of offsite power,b) Transfer its loads to the offsite power source, andc) Be restored to its standby status.10) Verifying that the diesel generator operating in a test mode, connected to its bus, asimulated Safety Injection signal overrides the test mode by: (1) returning the dieselgenerator to standby operation, and (2) automatically energizing the emergency loadswith offsite power;,11) Verifying that the fuel transfer pump transfers fuel from the fuel storage tank (Unit 3), fuelstorage tanks (Unit 4) to the day tanks of each diesel associated with the unit via theinstalled cross-connection lines;12) Verifying that the automatic load sequence timer is OPERABLE with the interval betweeneach load block within +/- 10% of its design interval;
: 13) Verifying that the diesel generator lockout relay prevents the diesel generator fromstarting;
** If verification of the diesel's ability to restart and accelerate to a generator voltage and frequency of3950-4350 volts and 60 +/- 0.6 Hz within 15 seconds following the 24 hour operation test ofSpecification.
4.8.1.1.2.g.7) is not satisfactorily completed, it is not necessary to repeat the 24-hour test.Instead, the diesel generator may be operated between 2300-2500 kW Unit 3, 2650-2850 kW (Unit 4) for2 hours or until operating temperature has stabilized (whichever is greater).
Following the *2 hours/operating temperature stabilization run, the EDG is to be secured and restarted within 5 minutesto confirm its ability to achieve the required voltage and frequency within 15 seconds.TURKEY POINT -UNITS 3 & 43/4 8-8AMENDMENT NOS. 249 AND 245 ELECTRICAL POWER SYSTEMSSURVEILLANCE REQUIREMENTS (continued)~
: h. At lepst once peF 10 yesars or after any modifications which could affect diesel generator S-rependence by starting all required diesel generators simultaneously and verifying that all required diesel generators provide 60 -0.6 Hz frequency and 3950-4350 volts inlInsert 1 less than or equal to 15 seconds:
and1) Draining each fuel oil storage tank, removing the accumulated sediment andcleaning the tank.*2) For Unit 4 only, performing a pressure test of those portions of the diesel fuel oilsystem designed to Section III, subsection ND of the ASME Code in accordance with Section Xl of the ASME Boiler and Pressure Vessel Code and applicable Addenda.4.8.1.1.3 Reports -(Not Used)* A temporary Class III fuel storage system containing a minimum volume of 38,000 gallons of fuel oil may beused for up to 10 days during the performance of Surveillance Requirement 4.8.1.1.2i.
I for the Unit 3 storage tankwhile Unit 3 is in Modes 5, 6, or defueled.
If the diesel fuel oil storage tank is not returned to service within10 days, Technical Specification 3.8.1.1 Action b and 3.8.1.2 Action apply to Unit 4 and Unit 3 respectively.
TURKEY POINT -UNITS 3 & 43/4 8-9AMENDMENT NOS. -249 AND 45 D.C. SOURCESLIMITING CONDITION FOR OPERATION ACTION:(Continued)
: b. With one of the required battery banks inoperable, or with none of the full-capacity chargersassociated with a battery bank OPERABLE, restore all battery banks to OPERABLE status and atleast one charger associated with each battery bank to OPERABLE status within two hours* orbe in at least HOT STANDBY within the next 12 hours and in COLD SHUTDOWN within thefollowing 30 hours. This ACTION applies to both units simultaneously.
SURVEILLANCE REQUIREMENTS 4.8.2.1 Each 125-volt battery bank and its associated full capacity charger(s) shall be demonstrated OPERABLE:
a.1)n eFrF days by verifying that:The parameters in Table 4.8-2 meet the Category A limits, andThe total battery terminal voltage is greater than or equal to 129 volts on float charge andthe battery charger(s) output voltage is > 129 volts, andIf two battery chargers are connected to the battery bank, verify each battery charger issupplying a minimum of 10 amperes, or demonstrate that the battery charger supplying less than 10 amperes will accept and supply the D.C. bus load independent of itsassociated battery charger..nz, .or 02 days and within 7 days after a battery discharge with battery terminal voltager05 volts (108.6 volts for spare battery D-52), or battery overcharge with battery terminalabove 143 volts, by verifying that:The parameters in Table 4.8-2 meet the Category B limits,The average electrolyte temperature of every sixth cell is above 600F, and 4-There is no visible corrosion at either terminals or connectors, or verify battery connection\,6 resistance is:Battery Connection Limit (Micro-Ohms) 3B, 4A inter-cell
/ termination
< 29inter-cell (brace locations)
< 30transition cables < 125ortotal battery connections
< 1958Ba ery Connection Limit (Micro-Ohms) 3A, B, D-52 inter-cell
/ termination
< 35inter-cell (brace locations)
< 40transition cables < 125ortotal battery connections
< 2463C.At gast ence per 18 months by verifying that:1) The cells, cell plates, and battery racks show no visual indication of physical damage orabnormal deterioration,
*Can be extended to 24 hours if the oppsite unit is in MODE 5 or 6 and each of the remaining required batterychargers is capable of being powered from its associated diesel generator(s).
TURKEY POINT -UNITS 3 & 43/4 8-14AMENDMENT NOS. 25i&#xfd; AND 24-D.C. SOURCESSURVEILLANCE REOUIREMENTS (Continued)s 2)The cell-to-cell and terminal connections are clean, tight, and coated with anticorrosion
: material,
: 3) Each 400 amp battery charger (associated with Battery Banks 3A and 4B) will supply atleast 400 amperes at > 129 volts for at least 8 hours, and each 300 amp battery charger(associated with Battery Banks 3B and 4A) will supply at least 300 amperes at _> 129volts for at least 8 hours, and4) Battery Connection resistance is:Battery Connection Limit (Micro-Ohms) 3B, 4A inter-cell
/ termination
< 29inter-cell (brace locations)
< 30transition cables < 125ortotal battery connections
< 1958Battery Connection Limit (Micro-Ohms) 3A, 4B, D-52 inter-cell
/ termination
< 35inter-cell (brace locations)
< 40transition cables < 125ortotal battery connections
<2463d. ,t I8c p ronths, during shutdown**,
by verifying that the battery capacity isade e to supply and maintain in OPERABLE status all of the actual or simulated emergency I ds for the design duty cycle when the battery is subjected to a battery service test.e. At least once per 12 months, during shutdown**,
by giving performance discharge tests ofbattery capacity to any battery that shows signs of degradation or has reached 85% [75% forBatteries 4B and D52 (Spare) when used in place of Battery 4B] of service life expected for theapplication.
Degradation is indicated when the battery capacity drops more than 10% [7% forIlnsert 1 Batteries 4B and D52 (Spare) when used in place of Battery 4B] of rated capacity from itsaverage on previous performance tests, or is below 90% [93% for Batteries 48 and D52 (Spare)when used in place of Battery 4B] of the manufacturer's rating.)T. A la i no , p. , ,, ,t, , , durinrg UI .WULU wI , by LIIaL LI)e baLttry .LpaILy Is dL. 1e .I.80% [87% for Batteries 4B and D52 (Spare) when used in place of Battery 4B] of themanufacturer's rating when subjected to a performance discharge test. Once per 60-monthinterval this performance discharge test may be performed in lieu of the battery service testrequired by Specification 4.8.2.1.d.
**Except that the spare battery bank D-52, and any other battery out of service when spare battery bank D-52 isin service may be tested with simulated loads during operation.
TURKEY POINT -UNITS 3 & 43/4 8-15AMENDMENT NOS. 526 AND M48 ONSITE POWER DISTRIBUTION LIMITING CONDITION FOR OPERATION (Continued)
ACTION: (Continued) within 24 hours or be in at least HOT STANDBY within the next 12 hours and in COLDSHUTDOWN within the following 30 hours. This ACTION applies to both units simultaneously.
: d. With one D.C. bus not energized from its associated battery bank or associated charger,reenergize the D.C. bus from its associated battery bank within 2 hours* or be in at least HOTSTANDBY within the next 12 hours and in COLD SHUTDOWN within the following 30 hours. ThisACTION applies to both units simultaneously.
SURVEILLANCE REQUIREMENTS 4.8.3.1 The specified busses shall be determined energized and aligned in the required manner at least-enee-pef-
---days by verifying correct breaker alignment and indicated voltage on the bussesInsert 1* Can be extended to 24 hours if the opposite unit is in MODE 5 or 6 and each of the remaining required batterychargers is capable of being powered from its associated diesel generator(s).
TURKEY POINT -UNITS 3 & 43/4 8-20AMENDMENT NOS.--3!
AND i-ONSITE POWER DISTRIBUTION SHUTDOWNLIMITING CONDITION FOR OPERATION 3.8.3.2 As a minimum, the following electrical busses shall be energized in the specified manner:a. One train of A.C. emergency busses associated with the unit (3.8.3.1a.
or b.) consisting of one4160-volt and three 480-volt A.C. emergency busses load centers*
and three (four for Unit 4Train A) vital sections of motor control center busses,b. Two 120-volt A.C. vital busses for the unit energized from their associated inverters**
connected to their respective D.C. busses, andc. Three 125-volt D.C. busses energized from their associated battery banks.APPLICABILITY MODES 5*** and 6***.ACTION:With any of the above required electrical busses not energized in the required manner, immediately suspend alloperations involving CORE ALTERATIONS, positive reactivity
: changes, or movement of irradiated fuel, initiatecorrective action to energize the required electrical busses in the specified manner as soon as possible, andwithin 8 hours, depressurize and vent the RCS through at least a 2.2 square inch vent.SURVEI LLANCE REQUIREMENTS 4.8.3.2 The specified busses shall be determined energized in the required manner at lcast ence por 7 days byverifying correct breaker alignment and indicated voltage on the busseIlnsert 11*With the opposite unit in MODE 1, 2, 3, or 4, the 480-volt load centers can only be cross-tied upon issuance ofan engineering evaluation to prevent exceeding required electrical components maximum design ratings and toensure availability of the minimum required equipment.
**A backup inverter may be used to replace the normal inverter provided the normal inverter on the same DCbus for the opposite unit is not replaced at the same time.***CAUTION
-If the opposite unit is in MODES 1, 2, 3, or 4, see the corresponding Limiting Condition forOperation 3.8.3.1.TURKEY POINT -UNITS 3 & 43/4 8-23AMENDMENT NOS. 45-AND 440-3/4.9 REFUELING OPERATIONS 3/4.9.1 BORON CONCENTRATION LIMITING CONDITION FOR OPERATION 3.9.1 The boron concentration of all filled portions of the Reactor Coolant System and the refueling canal shallbe maintained uniform and sufficient to ensure that the more restrictive of the following reactivity conditions ismet; either:a. A Keft of 0.95 or less, orb. A boron concentration of greater than or equal to 2300 ppm.APPLICABILITY:
MODE 6.*ACTION:With the requirements of the above specification not satisfied, immediately suspend all operations involving CORE ALTERATIONS or positive reactivity changes and initiate and continue boration at greater than or equal to16 gpm of a solution containing greater than or equal to 3.0 wt% (5245 ppm) boron or its equivalent until KIf isreduced to less than or equal to 0.95 or the boron concentration is restored to greater than or equal to 2300 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, andb. Withdrawal of any full-length control rod in excess of 3 feet from its fully inserted position withinthe reactor vessel.4.9.1.2 The boron concentration of the Reactor Coolant System and the refueling canal shall be determined bychemical analysis at least mcc pe 72 h.U.S.4.9.1.3 Valves isolating unbbstops or by removal of air orand secured in position by mechanical
* The reactor shall be maintained in MODE 6 whenever fuel is in the reactor vessel with the vessel head closurebolts less than fully tensioned or with the head removed.** The primary water supply to the boric acid blender may be opened under administrative controls for makeup.TURKEY POINT -UNITS 3 & 43/4 9-1AMENDMENT NOS.-2-4 AND 246-REFUELING OPERATIONS 3/4.9.2 INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.9.2 As a minimum, one primary Source Range Neutron Flux Monitor with continuous visual indication in thecontrol room and audible indication in the containment and control room, and one of the remaining three SourceRange Neutron Flux Monitors (one primary or one of the two backup monitors) with continuous visual indication inthe control room shall be OPERABLE.
APPLICABILITY:
MODE 6.ACTION:a. With one of the above required monitors inoperable or not operating, immediately suspend alloperations involving CORE ALTERATIONS or positive reactivity changes.b. With both of the above required monitors inoperable or not operating, determine the boronconcentration of the Reactor Coolant System at least once per 12 hours.-SURVEILLANCE REQUIREMENTS 4.9.2 Each required Source Range Neutron Flux Monitor shall be demonstrated OPERABLE by performance of:a. A CHANNEL CHECK last on- per 12 hnrsirb. An ANALOG CHANNEL OPRATIONAL TEST within 8 hours prior to the initial start of COREALTERATIONS, andc. An ANALOG CHANNEL 0 FERATIONAL TEST at leastne Der-7dTURKEY POINT -UNITS 3 & 43/4 9-2AMENDMENT NOS. 4-37 AND 4-3 REFUELING OPERATIONS 3/4.9.8 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION HIGH WATER LEVELLIMITING CONDITION FOR OPERATION 3.9.8.1 At least one residual heat removal (RHR) loop shall be OPERABLE and in operation.*
APPLICABILITY:
MODE 6, when the water level above the top of the reactor vessel flange is greater than orequal to 23 feet.ACTION:With no RHR loop OPERABLE and in operation, suspend all operations involving an increase in the reactor decayheat load or a reduction in boron concentration of the Reactor Coolant System and immediately initiate corrective action to return the required RHR loop to OPERABLE and operating status as soon as possible.
Close allcontainment penetrations providing direct access from the containment atmosphere to the outside atmosphere within 4 hours.SURVEILLANCE REQUIREMENTS 4.9.8.1.1 At least one RHR loop shall be verified in operation and circulating reactor coolant at a flow rate ofgreater than or equal to 3000 gpm t o r 12 hours.4.9.8.1.2 The RHR flow indicator shall be subjecte a CHANNEL CALIBRATION at least enee 18 u I I i S.1 Il1,.7*The required RHR loop may be removed from operation for up to 1 hour per 8 hour period, provided nooperations are permitted that would cause reduction of the Reactor Coolant System boron concentration.
TURKEY POINT -UNITS 3 & 43/4 9-8AMENDMENT NOS. 8-89-AND 48 REFUELING OPERATIONS LOW WATER LEVELLIMITING CONDITION FOR OPERATION 3.9.8.2 Two independent residual heat removal (RHR) loops shall be OPERABLE, and at least one RHR loopshall be in operation*.
APPLICABILITY:
MODE 6, when the water level above the top of the reactor vessel flange is less than 23 feet.ACTION:a. With less than the required RHR loops OPERABLE, immediately initiate corrective action toreturn the required RHR loops to OPERABLE status, or to establish greater than or equal to23 feet of water above the reactor vessel flange, as soon as possible.
: b. With no RHR loop in operation, suspend all operations involving a reduction in boronconcentration of the Reactor Coolant System and immediately initiate corrective action to returnthe required RHR loop to operation.
Close all containment penetrations providing direct accessfrom the containment atmosphere to the outside atmosphere within 4 hours.SURVEILLANCE REQUIREMENTS 1y4.9.8.2 At least one RHR loop shall be verified in operation and circulating reactor coolant at a flow rate ofgreater than or equal to 3000 gpm at least once per heurs.IInser 1I* One required RHR loop may be inoperable for up to 2 hours for surveillance
: testing, provided that the otherRHR loop is OPERABLE and in operation.
TURKEY POINT -UNITS 3 & 43/4 9-9AMENDMENT NOS. 229-AND REFUELING OPERATIONS 3/4.9.11 WATER LEVEL -STORAGE POOLLIMITING CONDITION FOR OPERATION 3.9.11 The water level shall be maintained greater than or equal to elevation 56' -10" the spent fuel storagepool.*APPLICABILITY:
Whenever irradiated fuel assemblies are in the storage pool.ACTION:a. With the requirements of the above specification not satisfied, suspend all movement of fuelassemblies and crane operations with loads in the fuel storage areas and restore the water levelto within its limit within 4 hours.b. The provisions of Specification 3.0.3 are not applicable.
Insert 1S VEILLANCE REQUIREMENTS 4.9.11 The water level in the storage pool shall be determined to be at least its minimum required depth at4eest-..... 7 ,e, daywhen irradiated fuel assemblies are in the fuel storage pool.*The requirements of this specification may be suspended for more than 4 hours to perform maintenance provided a 10 CFR 50.59 evaluation is prepared prior to suspension of the above requirement and all movementof fuel assemblies and crane operation with loads in the fuel storage areas are suspended.
If the level is notrestored within 7 days, the NRC shall be notified within the next 24 hours.TURKEY POINT -UNITS 3 & 43/4 9-12AMENDMENT NOS. 224-AND249-REFUELING OPERATIONS 3/4.9.14 SPENT FUEL STORAGELIMITING CONDITION FOR OPERATION 3.9.14 The following conditions shall apply to spent fuel storage:a. The minimum boron concentration in the Spent Fuel Pit shall be 2300 ppm.b. The combination of initial enrichment, burnup, and cooling time of each fuel assembly stored inthe Spent Fuel Pit shall be in accordance with Specification 5.5.1.APPLICABILITY:
At all times when fuel is stored in the Spent Fuel Pit.ACTION:a. With boron concentration in the Spent Fuel Pit less than 2300 ppm, suspend movement of spent ",,/fuel in the Spent Fuel Pit and initiate action to restore boron concentration to 2300 ppm or ANgreater.b. With condition b not satisfied, suspend movement of additional fuel assemblies into the SpentFuel Pit and restore the spent fuel storage configuration to within the specified conditions.
c, The provisions of Specification 3.0.3 are not applicable.
SURVEI LLANCE REQUIREMENTS 4.9.14.1 The boron concentration of the Spent Fuel Pit shall be verified to be 2300 ppm or greater at least en-eeeper month,4.9.14.2 A representative sample of inservice Metamic inserts shall be visually inspected in accord ce withthe Metamic Surveillance Program described in UFSAR Section 16.2. The surveillance ogramensures that the performance requirements of Metamic are met over the surveillance i erval.TURKEY POINT -UNITS 3 & 43/4 9-15AMENDMENT NOS. 249 AND 24t SPECIAL TEST EXCEPTIONS 3/4.10.3 PHYSICS TESTSLIMITING CONDITION FOR OPERATION 3.10.3 The limitations of Specifications 3.1.1.3, 3.1.1.4, 3.1.3.1, 3.1.3.5, and 3.1.3.6 may be suspended duringthe performance of PHYSICS TESTS provided:
: a. The THERMAL POWER does not exceed 5% of RATED THERMAL POWER,b. The Reactor Trip Setpoints on the OPERABLE Intermediate and Power Range channels are setat less than or equal to 25% of RATED THERMAL POWER, andc. The Reactor Coolant System lowest operating loop temperature (Tavg) is greater than or equal to531&deg;F.APPLICABILITY:
MODE 2.ACTION:a. With the THERMAL POWER greater than 5% of RATED THERMAL POWER, immediately openthe Reactor trip breakers.
: b. With a Reactor Coolant System operating loop temperature (Ta,) less than 531 OF, restore Tavg towithin its limit within 15 minutes or be in at least HOT STANDBY within the next 15 minutes.SURVEILLANCE REQUIREMENTS 4.10.3.1 The THERMAL POWER shall be determined to be less than or equal to 5% of RATED THERMALPOWER at lcost encc per hour during PHYSICS TESTS.4.10.3.2 ach Intermediate and Power Range channel shall be subjected to an ANALOG CHANNELOPERAT NAL TEST within 12 hours prior to initiating PHYSICS TESTS.4.10.3 The Reactor Coolant System temperature (Tavg) shall be determined to be greater than or equal to5310 /at lcast oR-cc per 30 minutcs during PHYSICS TESTS.[insert 1TURKEY POINT -UNITS 3 & 43/4 10-3AMENDMENT NOS. 4-AND 4-2 ADMINISTRATIVE CONTROLSPROCEDURES AND PROGRAMS (Continued)
: 3. If crack indications are found in any portion of a SG tube not excluded above,then the next inspection for each affected and potentially affected SG for thedegradation mechanism that caused the crack indication shall not exceed 24effective full power months or one refueling outage (whichever results in morefrequent inspections).
If definitive information, such as from examination of apulled tube, diagnostic non-destructive
: testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s),
then theindication need not be treated as a crack.e. Provisions for monitoring operational primary-secondary leakage.k. Control Room Envelope Habitability ProgramA Control Room Envelope (CRE) Habitability Program shall be established and implemented toensure that CRE habitability is maintained such that, with an OPERABLE Control RoomEmergency Ventilation System (CREVS),
CRE occupants can control the reactor safely undernormal conditions and maintain it in a safe condition following a radiological event, hazardous chemical
: release, or a smoke challenge.
The program shall ensure that adequate radiation protection is provided to permit access and occupancy of the CRE under design basis accident(DBA) conditions without personnel receiving radiation exposures in excess of 5 rem totaleffective dose equivalent (TEDE) for the duration of the accident.
The program shall include the following elements:
: a. The definition of the CRE and the CRE boundary.
: b. Requirements for maintaining the CRE boundary in its design condition including configuration control and preventive maintenance.
: c. Requirements for (i) determining the unfiltered air inleakage past the CRE boundary intothe CRE in accordance with the testing methods and at the Frequencies specified inSections C.1 and C.2 of Regulatory Guide 1.197, "Demonstrating Control RoomEnvelope Integrity at Nuclear Power Reactors,"
Revision 0, May 2003, and (ii) assessing CRE habitability at the Frequencies specified in Sections C.1 and C.2 of Regulatory Guide 1.197, Revision 0.d. Measurement, at designated locations, of the CRE pressure relative to external areasadjacent to the CRE boundary during the pressurization mode of operation of theCREVS, operating at the flow rate required by Surveillance Requirement 4.7.5.d, at aFrequency of 18 months. Additionally, the supply fans (trains A and B) will be tested on astaggered test basis (defined in Technical Specification definition 1.29 every 36 months).The results shall be trended and the CRE boundary assessed every 18 months.e. The quantitative limits on unfiltered air inleakage into the CRE. These limits shall bestated in a manner to allow direct comparison to the unfiltered air inleakage measured bythe 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 DBAconsequences.
Unfiltered air inleakage limits for hazardous chemicals must ensure thatexposure of CRE occupants to these hazards will be within the assumptions in thelicensing basis.Insert 2 f. The provisions of Specification 4.0.2 are applicable to the Frequencies for assessing CRE habitability, determining CRE unfiltered inleakage, and measuring CRE pressureand assessing the CRE boundary as required by paragraphs c and d, respectively.
6.8.5 DELETEDTURKEY POINT -UNITS 3 & 46-1 8cAMENDMENT NOS. mn&#xfd;5&AND 7M4 Turkey Point Units 3 and 4 L-2014-033 Docket Nos. 50-250 and 50-251 Attachment 4Attachment 4Turkey Point Nuclear PlantLicense Amendment Request No. LAR-229Technical Specifications BasesMarked-Up PagesFor Information OnlyThis coversheet plus 19 pages.
REVISION NO.: PROCEDURE TITLE: PAGE:TECHNICAL SPECIFICATION BASES CONTROL PROGRAM 55 of 192PROCEDURE NO,:O-ADM-536 TURKEY POINT PLANTATTACHMENT 2Technical Specification Bases(Page 39 of 176)3/4.1.3 (Continued)
TS 3.1.3.2 Action a.2.c) requires the use of the Movable IncoreDetector System to verify rod position prior to increasing thermal powerabove 50 percent Rated Thermal Power (RTP) and within 8 hours ofreaching 100 percent RTP. These provisions are intended to establish and confirm the position of the rod with the inoperable RPI to ensurethat power distribution requirements are NOT violated.
The ACTION Statements which permit limited variations from the basicrequirements are accompanied by additional restrictions which ensurethat the original design criteria are met. Misalignment of a rod requiresmeasurement of peaking factors and a restriction in THERMALPOWER. These restrictions provide assurance of fuel rod integrity during continued operation.
In addition, those safety analyses affectedby a misaligned rod are reevaluated to confirm that the results remainvalid during future operation.
The maximum rod drop time restriction is consistent with the assumedrod drop time used in the safety analyses.
Measurement with Tavggreater than or equal to 500OF and with all Reactor Coolant Pumpsoperating ensures that the measured drop times will be representative of insertion times experienced during a Reactor Trip at operating conditions.
Control rod positions and OPERABILITY of the Rod Position Indicators are required to be verified on a nominal basis of e,-ee per 12 h'-rcwith more frequent verifications required if an automatic monitoring channel is inoperable.
These verification frequencies are adequate forassuring that the applicable LCOs are satisfied.
REVISION NO.: PROCEDURE TITLE: PAGE:PROCEDURE NO.: TECHNICAL SPECIFICATION BASES CONTROL PROGRAM 65 of 192PROCEDURE NO.:O-ADM-536 TURKEY POINT PLANTATTACHMENT 2Technical Specification Bases(Page 49 of 176)3/4.2.5 DNB Parameters The limits on the DNB-related parameters assure that each of theparameters are maintained within the normal steady-state envelope ofoperation assumed in the transient and accident analyses.
The limitsare consistent with the initial UFSAR assumptions and have beenanalytically demonstrated adequate to maintain a minimum DNBRabove the applicable design limits throughout each analyzed transient.
The limits for Tavg and pressurizer pressure have been moved to theCOLR. The measured RCS flow value of 270,000 gpm corresponds toa Thermal Design Flow of 260,700 gpm with an allowance of 3.5% toaccommodate calorimetric measurement uncertainty.
The ,2 H-O periodic surveillance of these parameters throughinstrument readout is sufficient to ensure that the parameters arerestored within their limits following load changes and other expectedtransient operation.
The 1.8 periodic measurement of the RCStotal flow rate is adequate to ensure that the DNB-related flowassumption is met and to ensure correlation of the flow indication channels with measured flow. The indicated percent flow surveillance z,-. a 1 2 huF will provide sufficient verification that flowdegradation has NOT occurred.
An indicated percent flow which isgreater than the thermal design flow plus instrument channelinaccuracies and parallax errors is acceptable for the 12 he'.'surveillance on RCS flow. To minimize measurement uncertainties itis assumed that the RCS flow channel outputs are averaged.
REVISION NO.: PROCEDURE TITLE: PAGE:--9---- TECHNICAL SPECIFICATION BASES CONTROL PROGRAM 66 O1PROCEDURE NO.:O-ADM-536 TURKEY POINT PLANTATTACHMENT 2Technical Specification Bases(Page 50 of 176)3/4.3 Instrumentation 3/4.3.1&3/4.3.2 Reactor Trip System and Engineered Safety FeaturesActuation System Instrumentation The OPERABILITY of the Reactor Trip System and the Engineered Safety Features Actuation System instrumentation and interlocks ensures that: (1) The associated ACTION and/or Reactor trip will beinitiated when the parameter monitored by each channel or combination thereof reaches its Setpoint (2) The specified coincidence logic ismaintained, (3) Sufficient redundancy is maintained to permit a channelto be out of-service for testing or maintenance (due to plant specificdesign, pulling fuses and using jumpers may be used to place channelsin trip), and (4) Sufficient system functional capability is available fromdiverse parameters.
The OPERABILITY of these systems is required to provide the overallreliability, redundancy, and diversity assumed available in the facilitydesign for the protection and mitigation of accident and transient conditions.
The integrated operation of each of these systems isconsistent with the assumptions used in the safety analyses.
TheSurveillance Requirements specified for these systems ensure that theoverall system functional capability is maintained comparable to theoriginal design standards.
The periodic surveillance teststhe .m.......m
,feze, are sufficient to demonstrate this capability.
Surveillances for the analog RPS/ESFAS Protection and Control rackinstrumentation have been extended to "-"4e "Fe in accordance withWCAP-10271, Evaluation of Surveillance Frequencies and Out ofService Times for the Reactor Protection Instrumentation System, andsupplements to that report as generically approved by the NRC anddocumented in their SERs (Letters to the Westinghouse Owner's Groupfrom the NRC dated February 21, 1985, February 22, 1989, andApril 30, 1990).Under some pressure and temperature conditions, certain surveillances for Safety Injection cannot be performed because of the system design.Allowance to change modes is provided under these conditions as longas the surveillances are completed within specified time requirements.
REVISION NO.: PROCEDURE TITLE: PAGE:-9--TECHNICAL SPECIFICATION BASES CONTROL PROGRAM 81 of 192PROCEDURE NO.:O-ADM-536 TURKEY POINT PLANTATTACHMENT 2Technical Specification Bases(Page 65 of 176)3/4.4.2 (Continued)
In MODE 5 only one Pressurizer Code Safety is required foroverpressure protection.
In lieu of an actual OPERABLE Code SafetyValve, an unisolated and unsealed vent pathway (i.e., a direct,unimpaired
: opening, a vent pathway with valves locked open and/orpower removed and locked on an open valve) of equivalent size can betaken credit for as synonymous with an OPERABLE Code Safety.Demonstration of the safety valves lift settings will occur only duringshutdown and will be performed in accordance with the provisions ofthe ASME OM Code. The Pressurizer Code Safety Valves lift settingsallows a +2%, -3% setpoint tolerance for OPERABILITY;
: however, thevalves are reset to within +/-1% during the surveillance to allow for drift.3/4.4.3 Pressurizer The l.Hetrr periodic surveillance is sufficient to ensure that themaximum water volume parameter is restored to within its limitfollowing expected transient operation.
The maximum water volume(1133 cubic feet) ensures that a steam bubble is formed and thus theRCS is NOT a hydraulically solid system. The requirement that bothbackup pressurizer heater groups be OPERABLE enhances thecapability of the plant to control Reactor Coolant System pressure andestablish natural circulation.
3/4.4.4 Relief ValvesThe opening of the power-operated relief valves (PORVs) fulfills NOsafety-related function and NO credit is taken for their operation in thesafety analysis for MODE 1, 2 or 3. Equipment necessary to establish PORV operability in Modes 1 and 2 is limited to Vital DC power andthe Instrument Air system. Equipment necessary to establish blockvalve operability is limited to an AC power source. Each PORV has aremotely operated block valve to provide a positive shutoff capability should a PORV fail in the open position.
REVISION NO.: PROCEDURE TITLE: PAGE:_ 9_ _ TECHNICAL SPECIFICATION BASES CONTROL PROGRAM 99 of 192PROCEDURE NO.:O-ADM-536 TURKEY POINT PLANTATTACHMENT 2Technical Specification Bases(Page 83 of 176)3/4.4.6.2 (Continued)
Action d.With one or more RCS Pressure Isolation Valves with leakage greaterthan 5 gpm, the leakage must be reduced to below 5 gpm within 1 houror the reactor must be brought to at least HOT STANDBY within6 hours and COLD SHUTDOWN within the following 30 hours.The allowable outage times are reasonable, based on operating experience, to reach the required plant conditions from full powerconditions in an orderly manner and without challenging plantsystems.
In MODE 5, the pressure stresses acting on the RCPBare much lower, and further deterioration is much less likely.Surveillance Requirements SR 4.4.6.2.1 Verifying Reactor Coolant System leakage to be within the LCOlimits ensures the integrity of the Reactor Coolant PressureBoundary is maintained.
PRESSURE BOUNDARY LEAKAGEwould at first appear as UNIDENTIFIED LEAKAGE and can only bepositively identified by inspection.
It should be noted that leakagepast seals and gaskets is NOT PRESSURE BOUNDARYLEAKAGE.
UNIDENTIFIED LEAKAGE and IDENTIFIED LEAKAGE are determined by performance of a Reactor CoolantSystem water inventory balance.a. & b.These SRs demonstrate that the RCS operational leakage is withinthe LCO limits by monitoring the containment atmosphere gaseousor particulate radioactivity monitor and the containment sump levelat le@19t eme pe 12 hom REVISION NO.: PROCEDURE TITLE: PAGE:TECHNICAL SPECIFICATION BASES CONTROL PROGRAM 100 of 192PROCEDURE NO.:0-ADM-536 TURKEY POINT PLANTATTACHMENT 2Technical Specification Bases(Page 84 of 176)3/4.4.6.2 (Continued)
C.The RCS water inventory balance must be performed with the reactorat steady state operating conditions and near operating pressure.
TheSurveillance is modified by two notes. Note *** states that this SR isNOT required to be performed until 12 hours after establishment ofsteady state operation.
The 12 hour allowance provides sufficient timeto collect and process all necessary data after stable plant conditions are established.
Steady state operations is required to perform a proper inventory balance since calculations during maneuvering are NOT useful. ForRCS operational leakage determination by water inventory balance,steady state is defined as stable RCS pressure, temperature, powerlevel, Pressurizer and makeup tank levels, makeup and letdown, andReactor Coolant Pump seal injection and return flows.An early warning of PRESSURE BOUNDARY LEAKAGE orUNIDENTIFIED LEAKAGE is provided by the automatic systems thatmonitor containment atmosphere radioactivity, containment normalsump inventory and discharge, and reactor head flange leak-off.
Itshould be noted that leakage past seals and gaskets is NOTPRESSURE BOUNDARY LEAKAGE.
These leakage detection systems are specified in LCO 3.4.6.1, Reactor Coolant SystemLeakage Detection Systems.Note ** states that this SR is NOT applicable to primary-to-secondary leakage because leakage of 150 gallons per day cannot be measuredaccurately by an RCS water inventory balance.The 72.4&6 frequency is a reasonable interval to trend leakage andrecognizes the importance of early leakage detection in the prevention of accidents.
d.This SR demonstrates that the RCS Operational Leakage is withinthe LCO limits by monitoring the Reactor Head Flange Leak-offSystem at loe t .... e p, ..h24 ..
REVISION NO.: PROCEDURE TITLE: PAGE:--9--TECHNICAL SPECIFICATION BASES CONTROL PROGRAM 101PROCEDURE NO.:0-ADM-536 TURKEY POINT PLANTATTACHMENT 2Technical Specification Bases(Page 85 of 176)3/4.4.6.2 (Continued) e.This SR verifies that primary-to-secondary leakage is less than orequal to 150 gpd through any one SG. Satisfying theprimary-to-secondary leakage limit ensure that the operational leakageperformance criterion in the Steam Generator Program is met. If thisSR is NOT met, compliance with LCO 3.4.5, Steam Generator (SG)Tube Integrity, should be evaluated.
The 150-gpd limit is measured atroom temperature as described in Reference
: 5. The operational leakage rate limit applies to leakage through any one SG. If it is NOTpractical to assign the leakage to an individual SG, all the primary tosecondary leakage should be conservatively assumed to be from oneSG.The SR is modified by Note ***, which states that the Surveillance isNOT required to be performed until 12 hours after establishment ofsteady state operation.
For RCS primary to-secondary leakagedetermination, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeupand letdown, and reactor coolant pump seal injection and return flows.The surveillance frequency 4-e is a reasonable interval to trendprimary to secondary leakage and recognizes the importance of earlyleakage detection in the prevention of accidents.
Theprimary-to-secondary leakage is determined using continuous processradiation monitors or radiochemical grab sampling in accordance withthe EPRI guidelines (Ref. 5).SR 4.4.6.2.2 It is apparent that when pressure isolation is provided by two in-series check valves and when failure of one valve in the pair can goundetected for a substantial length of time, verification of valve integrity is required.
Since these valves are important in preventing overpressurization and rupture of the ECCS low pressure piping, whichcould result in a LOCA that bypasses containment, these valvesshould be tested periodically to ensure low probability of gross failure.
REVISION NO.: PROCEDURE TITLE: PAGE:--9---TECHNICAL SPECIFICATION BASES CONTROL PROGRAM 104 of 192PROCEDURE NO.:O-ADM-536 TURKEY POINT PLANTATTACHMENT 2Technical Specification Bases(Page 88 of 176)3/4.4.8 (Continued)
The RCS Specific activity satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).
The iodine specific activity in the reactor coolant is limited to0.25 pCi/gm DOSE EQUIVALENT 1-131, and the noble gas specificactivity in the reactor coolant is limited to 447.7 pCi/gm DOSEEQUIVALENT XE-1 33. The limits on specific activity ensure that theoffsite and Control Room doses will meet the appropriate SRPacceptance criteria.
The SLB, SGTR, Locked Rotor, and RCCA Ejection Accident analysesshow that the calculated doses are within limits. Violation of the LCOmay result in reactor coolant activity levels that could, in the event ofany one of these accidents, lead to doses that exceed the acceptance criteria.
The ACTIONS permit limited operation when DOSE EQUIVALENT 1-131 is greater than 0.25 pCi/gm and less than 60 pCi/gm. TheActions require sampling within 4 hours and every 4 hours following toestablish a trend.One surveillance requires performing a gamma isotropic analysis as ameasure of noble gas specific activity of the reactor coolant atleeea-cnzc Per 7 days. This measurement is the sum of the degassedgamma activities and the gaseous gamma activities in the sampletaken. This surveillance provides an indication of any increase in thenoble gas specific activity.
A second surveillance is performed to ensure that iodine specificactivity remains within the LCO limit cncc pcr 14 day. during normaloperation and following fast power changes when iodine spiking ismore apt to occur. The frequency between 2 and 6 hours after apower change of greater than 15% RATED THERMAL POWER withina 1 hour period, is established because the iodine levels peak duringthis time following iodine spike initiation.
REVISION NO.: PROCEDURE TITLE: PAGE:TECHNICAL SPECIFICATION BASES CONTROL PROGRAM 122 of 192PROCEDURE NO.:O-ADM-536 TURKEY POINT PLANTATTACHMENT 2Technical Specification Bases(Page 106 of 176)3/4.5.2 & 3/4.5.3 (Continued)
When PC-600/-601 are calibrated, a test signal is supplied to each circuitto check operation of the relays and annunciators operated by subjectcontrollers.
This test signal will prevent MOVs 862A, 862B, 863A, 863Bfrom opening.
Therefore, it is appropriate to tag out the MOV breakers, and enter Technical Specification Action Statement 3.5.2.a.
and 3.6.2.1when calibrating PC-600/-601.
With the RCS temperature below 3500F, operation with less than fullredundant equipment is acceptable without single failure consideration onthe basis of the stable reactivity condition of the reactor and the limitedcore cooling requirements.
TS 3.5.2, Action g. provides an allowed outage/action completion time(AOT) of up to 7 days to restore an inoperable RHR Pump to OPERABLEstatus, provided the affected ECCS Subsystem is inoperable only becauseits associated RHR Pump is inoperable.
This 7 day AOT is based on theresults of a deterministic and probabilistic safety assessment, and isreferred to as a Risk-Informed AOT Extension.
Planned entry into thisAOT requires that a Risk Assessment be performed in accordance withthe Configuration Risk Management Program (CRMP), which is described in the administrative procedure that implements the Maintenance Rulepursuant to 10CFR50.56.
TS Surveillance 4.5.2.a requires that each ECCS component and flow pathbe demonstrated operable at least ....... 12 he by verifying byControl Room indication that the valves listed in Section 4.5.2.a are in theindicated positions with power to the valve operators removed.
Verifying Control Room indication applies to the valve position and NOT to the valveoperator power removal.
The breaker position may be verified by either theoff condition of the breaker position indication light in the Control Room, orthe verification of the locked open breaker position in the field. Verifying that power is removed to the applicable valve operators can beaccomplished by direct field indication of the breaker (locked in the openposition),
or by observation of the breaker position status lamp in theControl Room (lamp is off when breaker is open). Surveillance Requirements for throttle valve position stops prevent total pump flow fromexceeding runout conditions when the system is in its minimum resistance configuration.
REVISION NO.: PROCEDURE TITLE: PAGE:_9_ _ TECHNICAL SPECIFICATION BASES CONTROL PROGRAM 123 of 192PROCEDURE NO.:O-ADM-536 TURKEY POINT PLANTATTACHMENT 2Technical Specification Bases(Page 107 of 176)3/4.5.2 & 3/4.5.3 (Continued)
ECCS "accessible discharge piping" is defined as discharge piping outsideof containment in accordance with NRC Generic Letter 2008-01,Managing Gas Accumulation in Emergency Core Cooling, Decay HeatRemoval, and Containment Spray Systems interpretation.
High point vents(current or added) outside of containment on the HHSI and RHR Systemspriodc r piping are considered accessible.
These valves must beincluded In= venting procedure to comply with Technical Specification Surveillance Requirement 4.5.2.b.1.
This clarification wasadded as a corrective action to CR# 2009-18558.
In the RHR test, differential head is specified in feet. This criteria will allowfor compensation of test data with water density due to varying temperature.
ECCS pump testing for the SI and RHR Pumps accounts for possibleunderfrequency conditions, i.e., the results of pump testing performed at60 Hz is then adjusted to reflect possible degraded grid conditions (60+/-0.6) to the lower limit (59.4 Hz).CAUTIONInterim Compensatory MeasureTS 3.5.2 Action 'a' has been determined to be non-conservative with respect tothe safety analysis as it allows up to 72 hours for restoration of the inoperable flow path despite inoperability of both ECCS trains during this period.Therefore, until appropriate changes to TS 3/4.5.2 via LAR 212 are approvedand implemented, TS 3.0.3 shall be entered vice TS 3.5.2 Action 'a' in theevent that the suction flow path from the RWST to the ECCS is inoperable.
Reference AR 1811016.Technical Specifications Surveillance Requirement 4.5.2.e.3 requires thateach ECCS component and flow path be demonstrated OPERABLE ev'-4 8weI.tha by visual inspection which verifies sump components (trashracks, screens, etc.) show NO evidence of structural distress or abnormalcorrosion.
The strainer modules are rigid enough to provide both functions as trash racks and screens without losing their structural integrity andparticle efficiency.
Therefore, strainer modules are functionally equivalent to trash racks and screens.
Accordingly, the categorical description, sumpcomponents, is broad enough to require inspection of the strainer modules.
REVISION NO.: PROCEDURE TITLE: PAGE:TECHNICAL SPECIFICATION BASES CONTROL PROGRAM 133 of 192PROCEDURE NO.:O-ADM-536 TURKEY POINT PLANTATTACHMENT 2Technical Specification Bases(Page 117 of 176)3/4.6.2.2 (Continued)
The allowable out-of-service time requirements for the Containment Cooling System have been maintained consistent with that assignedother inoperable ESF equipment and do NOT reflect the additional redundancy in cooling capability provided by the Containment SpraySystem. The frequency The surveillance requirement for ECC flo verified by correlating thetest configuration value with the de i asis assumptions for systemconfiguration and flow. Am 13, -8 ,. 9,vil ,tr.l is acceptable based on the use of water from the CCW system, which results in alow risk of heat exchanger tube fouling.3/4.6.2.3 Recirculation PH Control SystemThe Recirculation pH Control System is a passive safeguard consisting of 10 stainless steel wire mesh baskets (2 large and 8 small)containing sodium tetra borate decahydrate (NaTB) located in thecontainment basement (14' elevation).
The initial containment spraywill be boric acid solution from the Refueling Water Storage Tank. Therecirculation pH control system adds NaTB to the Containment Sumpwhen the level of boric acid solution from the Containment Spray andthe coolant lost from the Reactor Coolant System rises above thebottom of the buffering agent baskets.
As the sump level rises, theNaTB will begin to dissolve.
The addition of NaTB from the buffering agent baskets ensures the containment sump pH will be greater than7.0. The resultant alkaline pH of the spray enhances the ability of therecirculated spray to scavenge fission products from the containment atmosphere.
The alkaline pH in the recirculation sump waterminimizes the evolution of iodine and minimizes the occurrence ofchloride and caustic stress corrosion on stainless steel piping systemsexposed to the solution.
The OPERABILITY of the recirculation pH control system ensures thatthere is sufficient NaTB available in the containment to ensure a sumppH greater than 7.0 during the recirculation phase of a postulated LOCA. The baskets will NOT interact with surrounding equipment during a seismic event.
REVISION NO.: PROCEDURE TITLE: PAGE:-9--TECHNICAL SPECIFICATION BASES CONTROL PROGRAM 135 of 192PROCEDURE NO.:0-ADM-536 TURKEY POINT PLANTATTACHMENT 2Technical Specification Bases(Page 119 of 176)3/4.6.2.3 (Continued)
To satisfy the surveillance requirement, the two large baskets andeight small baskets must contain a combined mass greater than7500 Ibm of NaTB. As shown in the above table, this will ensure thesump pH exceeds 7.0 at the onset of spray recirculation and for theduration of the analyzed 30-day period. The large baskets have alength and width of 54 inches, and a height of 33.25 inches and areelevated 3.5 inches above the containment floor. The smallerbaskets have a length and width of 36 inches and a height of30 inches and are elevated 4.5 inches above the containment floor.Varying basket dimensions or elevation (e.g. basket leg height)impacts the surface to volume ratio and changes the time the NaTBis in contact with containment sump water. For instance, shorter legswould allow the NaTB to contact containment sump water sooner,therefore increasing the pH at the onset of recirculation.
Longer legs,however, would reduce the pH at the onset of recirculation.
The levelof NaTB in the baskets required to provide an equilibrium sumpsolution pH greater than 7.0 is 14.75 inches from the top of the "basket; 18.50 inches for the large baskets and 15.25 inches for thesmall baskets from the bottom of the basket. The 1, e,,,thfrequency for Surveillance Requirement 4.6.2.3 is sufficient to ensurethat the stainless steel buffering agent baskets are intact and containthe required quantity of NaTB.
REVISION NO.: PROCEDURE TITLE: PAGE:--9-TECHNICAL SPECIFICATION BASES CONTROL PROGRAM 139 of 192PROCEDURE NO.:O-ADM-536 TURKEY POINT PLANTATTACHMENT 2Technical Specification Bases(Page 123 of 176)3/4.7.1.2 Auxiliary Feedwater SystemThe OPERABILITY of the Auxiliary Feedwater System ensures thatthe Reactor Coolant System can be cooled down to less than 350'Ffrom normal operating conditions in the event of a total Loss-Of-Offsite Power. Steam can be supplied to the pump turbines from either orboth units through redundant steam headers.
Two D.C. motoroperated valves and one A.C. motor operated valve on each unitisolate the three main steam lines from these headers.
Both the D.C.and A.C. motor operated valves are powered from safety-related sources.
Auxiliary feedwater can be supplied through redundant linesto the safety-related portions of the main feedwater lines to each of thesteam generators.
Air operated fail closed flow control valves areprovided to modulate the flow to each steam generator.
Each SteamDriven Auxiliary Feedwater Pump has sufficient capacity for single andtwo unit operation to ensure that adequate feedwater flow is available to remove decay heat and reduce the Reactor Coolant Systemtemperature to less than 350&deg;F when the Residual Heat RemovalSystem may be placed into operation.
ACTION statement 2 describes the actions to be taken when bothAuxiliary Feedwater Trains are inoperable.
The requirement to verifythe availability of both Standby Feedwater Pumps is to beperiodic accomplished by verifying that both pumps have successfully passedthei ,,,t,,y surveillance tests within the last surveillance interval.
Therequirement to complete this action before beginning a unit shutdown isto ensure that an alternate feedwater train is available before puttingthe affected unit through a transient.
If NO alternate feedwater trainsare available, the affected unit is to stay at the same condition until anauxiliary feedwater train is returned to service, and then invoke ACTIONstatement 1 for the other train. If both Standby Feedwater Pumps aremade available before one Auxiliary Feedwater Train is returned to anOPERABLE status, then the affected units shall be placed in at leastHOT STANDBY within 6 hours and HOT SHUTDOWN within thefollowing 6 hours.
REVISION NO.: PROCEDURE TITLE: PAGE:TECHNICAL SPECIFICATION BASES CONTROL PROGRAM 140 of 192PROCEDURE NO.:O-ADM-536 TURKEY POINT PLANTATTACHMENT 2Technical SDecification Bases(Page 124 of 176)3/4.7.1.2 (Continued)
ACTION statement 3 describes the actions to be taken when a singleAuxiliary Feedwater Pump is inoperable.
The requirement to verify thattwo independent Auxiliary Feedwater Trains are OPERABLE is to beaccomplished by verifying that the requirements for Table 3.7-3 havebeen successfully met for each train within the last surveillance interval.
The provisions of Specification 3.0.4 are NOT applicable to the thirdauxiliary feedwater pump provided it has NOT been inoperable forlonger than 30 days. This means that a units can changeOPERATIONAL MODES during a unit's heatup with a single Auxiliary Feedwater Pump inoperable as long as the requirements of ACTIONStatement 3 are satisfied.
The specified flow rate acceptance criteria conservatively bounds thelimiting AFW flow rate modeled in the single unit Loss Of NormalFeedwater analysis.
Dual unit events such as a two unit Loss Of OffsitePower require a higher pump flow rate, but it is NOT practical to testboth units simultaneously.
The m, 4lp4h' flow surveillance test specified in 4.7.1.2.1.1 is considered to be a general performance test for theAFW system and does NOT represent the limiting flow requirement forAFW. Check valves in the AFW system that require full stroke testingunder limiting flow conditions are tested under Technical Specification 4.0.5.The -hthly testing of the Auxiliary Feedwater Pumps will verify theirOPERABILITY.
Proper functioning of the turbine admission valve andthe operation of the pumps will demonstrate the integrity of the system.Verification of correct operation will be made both from instrumentation within the Control Room and direct visual observation of the pumps.
REVISION NO.: PROCEDURE TITLE: PAGE:'IS' TECHNICAL SPECIFICATION BASES CONTROL PROGRAM 144 of 192PROCEDURE NO.:O-ADM-536 TURKEY POINT PLANTATTACHMENT 2Technical Specification Bases(Page 128 of 176)3/4.7.1.6 (Continued)
The Standby Steam Generator Feedwater Pumps are NOT designed toNRC requirements applicable to Auxiliary Feedwater Systems and NOTrequired to satisfy Design Basis Events requirements.
These pumpsmay be out of service for up to 24 hours before initiating formalnotification because of the extremely low probability of a demand fortheir operation.
The guidelines for NRC notification in case of both pumps being out ofservice for longer than 24 hours are provided in applicable plantprocedures, as a voluntary 4 hour notification.
Adequate demineralized water for the Standby St amFeedwater system will be verified  hei9.
TheDemineralized Water Storage Tank provides a source of water toseveral systems and therefore, requires daily verification.
The Standby Steam Generator Feedwater Pumps will be verifiedOPERABLE me.th.y on a STAGGERED TEST BASIS by starting andoperating them in the recirculation mode. Also, during each unit'srefueling outage, each Standby Steam Generator Feedwater Pump willbe started and aligned to provide flow to the nuclear unit's steamgenerators.
This surveillance regimen will thus demonstrate operability of the entireflow path, backup non-safety grade power supply and pump associated with a unit at least each refueling outage. The pump, motor driver, andnormal power supply availability would typically be demonstrated byoperation of the pumps in the recirculation mode monthly on astaggered test basis.The diesel engine driver for the B Standby Steam Generator Feedwater Pump will be verified operable lllll ....... 94 days on a staggered testbasis perfor an by Steam Generator Feedwater Pump.pe.dl i ion, an inspection will be performed on the diesel Qat4eastQ~.
-in accordance with procedures prepared in conjunction with its manufacture's recommendations for the diesel's class of service.This inspection will ensure that the diesel driver is maintained in goodoperating condition consistent with FPLs overall objectives for systemreliability.
REVISION NO.: PROCEDURE TITLE: PAGE:TECHNICAL SPECIFICATION BASES CONTROL PROGRAM 146 o1PROCEDURE NO.:O-ADM-536 TURKEY POINT PLANTATTACHMENT 2Technical Specification Bases(Page 130 of 176)3/4.7.1.7 (Continued)
Inoperable FCVs and FIVs that are closed or isolated must be verifiedon a periodic basis that they are closed or isolated.
This is necessary toensure that the assumptions in the safety analysis remain valid.The 7 day Completion Time is reasonable in view of valve statusindications available in the Control Room, and other administrative
: controls, to ensure that these valves are closed or isolated.
With two valves in the same flow path inoperable, there may be NOredundant system to operate automatically and perform the requiredsafety function.
Although the Containment can be isolated with thefailure of two valves in parallel in the same flow path, the double failurecan be an indication of a common mode failure in the valves of this flowpath, and as such, is treated the same as a loss of the isolation capability of this flow path. Under these conditions, affected valves ineach flow path must be restored to OPERABLE status, or the affectedflow path isolated within 8 hours. This action returns the system to thecondition where at least one valve in each flow path is performing therequired safety function.
The 8 hour Completion Time is reasonable, based on operating experience, to complete the actions required toclose the FCV or FIV, or otherwise isolate the affected flow path.SR 4.7.1.7.a verifies that each FCV, FIV, and bypass line valve willactuate to its isolation position on an actuation or simulated actuation signal. The Frequency is based on a refueling cycle intervaland the potential for an unplanned transient if the Surveillance wereperformed with the reactor at power. Operating experience has shownthat these components usually pass this Surveillance when performed at the 18 month Frequency.
Therefore, the frequency was concluded tobe acceptable from a reliability standpoint.
SR 4.7.1.7.b verifies that the closure time of each FCV, FIV, and bypassline valve, when tested in accordance with the Inservice TestingProgram, is within the limits assumed in the accident and containment analyses.
This SR is normally performed upon returning the unit tooperation following a refueling outage. These valves should NOT betested at power, since even a part stroke exercise increases the risk of avalve closure with the unit generating power. This is consistent with theASME Code Section XI (Ref. 3), quarterly stroke requirements duringoperation in MODES 1 and 2.
REVISION NO.: PROCEDURE TITLE: PAGE:TECHNICAL SPECIFICATION BASES CONTROL PROGRAM 169 O1PROCEDURE NO.:O-ADM-536 TURKEY POINT PLANTATTACHMENT 2Technical Specification Bases(Page 153 of 176)3/4.8.1, 3/4.8.2 & 3/4.8.3 (Continued)
A thermographic examination of high-risk potential ignition sources inthe Cable Spreading Room and the Control Room,Restriction of planned hot work in the Cable Spreading Room andControl Room during the extended AOT, andEstablishment of a continuous fire watch in the Cable Spreading Room when in the extended AOT.In addition to the predetermined restrictions, assessments performed in accordance with the provisions of the Maintenance Rule (a)(4) willensure that any other risk significant configurations are identified before removing an EDG from service for pre-planned maintenance.
A configuration risk management program has been established atTurkey Point 3 and 4 via the implementation of the Maintenance Ruleand the On line Risk Monitor to ensure the risk impact of out of serviceequipment is appropriately evaluated prior to performing anymaintenance activity.
The Surveillance Requirements for demonstrating the OPERABILITY of the diesel generators are in accordance with the recommendations of Regulatory Guides 1.9, Selection of Diesel Generator Set Capacityfor Standby Power Supplies, March 10, 1971; 1.108, Periodic Testingof Diesel Generator Units Used as Onsite Electric Power Systems atNuclear Power Plants, Revision 1, August 1977; and 1.137, Fuel-oilSystems for Standby Diesel Generators, Revision 1, October 1979.The EDG Surveillance testing requires that each EDG be started fromnormal conditions ol"n pc" 1F 1 &deg;day, with NO additional warmupprocedures.
Normal conditions in this instance are defined as the pre-start temperature and lube oil conditions each EDG normally experiences with the continuous usE of prelube systems and immersion heaters.periodically REVISION NO.: PROCEDURE TITLE: PAGE:TECHNICAL SPECIFICATION BASES CONTROL PROGRAM 173 of 192PROCEDURE NO.:O-ADM-536 TURKEY POINT PLANTATTACHMENT 2Technical Specification Bases(Page 157 of 176)3/4.8.1, 3/4.8.2 & 3/4.8.3 (Continued)
Failure to meet any of the above limits is cause for rejecting the newfuel oil, but does NOT represent a failure to meet the Limiting Condition for Operation of TS 3.8.1.1, since the new fuel oil has NOT been addedto the Diesel Fuel Oil Storage Tanks.Within 30 days following the initial new fuel oil sample, the fuel oil isanalyzed to establish that the other properties specified in Table 1 ofASTM-D975-81 are met when tested in accordance withASTM-D975-81 except that the analysis for sulfur may be performed inaccordance with ASTM-D1552-79 or ASTM-D2622-82.
The 30 dayperiod is acceptable because the fuel oil properties of interest, even ifthey are NOT within limits, would NOT have an immediate effect onEDG operation.
The Diesel Fuel Oil Surveillance in accordance withthe Diesel Fuel Oil Testing Program will ensure the availability of highquality diesel fuel oil for the EDGs.Lubricity Specification for Ultra Low Sulfur Diesel Fuel OilTo ensure that Ultra Low Sulfur Diesel fuel (15 pm sulfur, S15) isacceptable for use in the Emergency Diesel Generators, a test is addedin the Diesel Fuel Oil Testing Program that validates, satisfactory lubricity
(
 
==Reference:==
 
Engineering Evaluation PTN-ENG-SEMS-06-0035).
The test for lubricity is based on ASTM D975-06, testing perASTM D6079, using the High Frequency Reciprocating Rig (HFRR) testat 60 degrees C and the acceptance criterion requires a wear scar NO3 larger than 520 microns.Ott least ... ever;y -.. dys, a sample of fuel oil is obtained from thestorage tanks in accordance with ASTM-D2276-78.
The particulate contamination is verified to be less than 10 mg/liter when checked inaccordance with ASTM-D2276-78, Method A. It is acceptable to obtaina field sample for subsequent laboratory testing in lieu of field testing.Fuel oil degradation during long term storage shows up as an increasein particulate, due mostly to oxidation.
The presence of particulate does NOT mean the fuel oil will NOT burn properly in a diesel engine.The particulate can cause fouling of filters and fuel oil injection equipment,
: however, which can cause engine failure.
REVISION NO.: PROCEDURE TITLE: PAGE:TECHNICAL SPECIFICATION BASES CONTROL PROGRAM 182 of 192PROCEDURE NO.:O-ADM-536 TURKEY POINT PLANTATTACHMENT 2Technical Specification Bases(Page 166 of 176)3/4.9 Refueling Operations 3/4.9.1 Boron Concentration The limitations on reactivity conditions during REFUELING ensure that:(1) The reactor will remain subcritical during CORE ALTERATIONS, and (2) A uniform boron concentration is maintained for reactivity control in the water volume having direct access to the reactor vessel.These limitations are consistent with the initial conditions assumed forthe boron dilution incident in the safety analyses.
With the requiredvalves closed during refueling operations the possibility of uncontrolled boron dilution of the filled portion of the RCS is precluded.
This actionprevents flow to the RCS of unborated water by closing flow paths fromsources of unborated water. The boration rate requirement of 16 gpmof 3.0 wt% (5245 ppm) boron or equivalent ensures the capability torestore the SHUTDOWN MARGIN with one OPERABLE chargingpump.The OPERABILITY of the Source Range Neutron Flux Monitorsensures that redundant monitoring capability is available to detectchanges in the reactivity condition of the core. There are four sourcerange neutron flux channels, two primary, and two backup. All fourchannels have visual and alarm indication in the Control Room andinterface with the containment evacuation alarm system. The primarysource range neutron flux channels can also generate reactor tripsignals and provide audible indication of the count rate in the ControlRoom and containment.
At least one primary source range neutronflux channel to provide the required audible indication, in addition to itsother functions, and one of the three remaining source range channelsshall be OPERABLE to satisfy the LCO.3/4.9.2 Instrumentation T.S. surveillance requirement 4.9.2.b and c states: edicallEach required Source Range Neutron Flux Monitor shall bedemonstrated OPERABLE by performance of:b. An ANALOG CHANNEL OPERATIONAL TEST within 8 hoursprior to the initial start of CORE ALTERATIONS, andc. An ANALOG CHANNEL OPERATIONAL TEST at eoa.t e.e.e ,pe,-- ay.. .o Turkey Point Units 3 and 4 L-2014-033 Docket Nos. 50-250 and 50-251 Attachment 5Attachment 5Turkey Point Nuclear PlantLicense Amendment Request No. LAR-229No Significant Hazards Consideration Determination Page 1 of 3 Turkey Point Units 3 and 4 L-2014-033 Docket Nos. 50-250 and 50-251 Attachment 5No Significant Hazards Consideration Description of Amendment Request:The change requests the adoption of an approved change to the Standard Technical Specifications (STS) for Westinghouse Plants (NUREG-1431) to allow relocation of specific TSsurveillance frequencies to a licensee-controlled program.
The proposed change is described inTechnical Specification Task Force (TSTF) Traveler, TSTF-425, Revision 3 (ADAMS Accession No. ML090800642) related to the Relocation of Surveillance Frequencies to Licensee Control -RITSTF Initiative 5b and was described in the Notice of Availability published in the FederalRegister on July 6, 2009 (74 FR 31966).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 change relocates surveillance frequencies to a licensee-controlled
: program, theSurveillance Frequency Control Program.
This change is applicable to licensees usingprobabilistic risk guidelines contained in NRC approved Nuclear Energy Institute (NEI) 04-10,"Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control ofSurveillance Frequencies,"
(ADAMS Accession No. ML071360456).
Surveillance frequencies that have a set periodicity will be relocated to the Surveillance Frequency Control Program controlled by the licensee.
Accordingly, changes to the periodicity can be made without prior NRC approval, provided they are made within the constraints of theProgram.
These constraints
: include, but are not limited to an engineering evaluation, anassessment of the risk associated with the change, and a review by an independent decision-making panel.Basis for proposed no significant hazards consideration:
As required by 10 CFR 50.91(a),
the FPL analysis of the issue of no significant hazardsconsideration is presented below:1. Does the proposed change involve a significant increase in the probability orconsequences of any accident previously evaluated?
Response:
NoThe proposed change relocates 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 aresult, the probability of any accident previously evaluated is not significantly increased.
The systems and components required by the technical specifications for which thesurveillance frequencies are relocated are still required to be operable, meet theacceptance criteria for the surveillance requirements, and be capable of performing anymitigation function assumed in the accident analysis.
As a result, the consequences ofany accident previously evaluated are not significantly increased.
Therefore, the proposed change does not involve a significant increase in the probability or consequences of any accident previously evaluated.
Page 2 of 3 Turkey Point Units 3 and 4 L-2014-033 Docket Nos. 50-250 and 50-251 Attachment
: 52. Does the proposed change create the possibility of a new or different kind of accidentfrom any previously evaluated?
Response:
NoThe proposed changes relocate the surveillance frequencies for Surveillance Requirements that have a set periodicity from the TS to a licensee controlled Surveillance Frequency Control Program.
This change does not alter any existingsurveillance frequencies.
Within the constraints of the Program, the licensee will be ableto change the periodicity of these surveillance requirements.
Relocating the surveillance frequencies does not impact the ability of structures, systems or components (SSCs)from performing there design functions, and thus, does not create the possibility of anew or different kind of accident from any previously evaluated.
No new or different accidents result from utilizing the proposed change. The changes donot 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.
Inaddition, the changes do not impose any new or different requirements.
The changes donot alter assumptions made in the safety analysis assumptions and current plantoperating practice.
Therefore, the proposed changes do not create the possibility of a new or different kindof accident from any accident previously evaluated.
: 3. Does the proposed change involve a significant reduction in the margin of safety?Response:
NoThe design, operation, testing methods, and acceptance criteria for systems, structures, and components (SSCs), 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 notaffected by changes to the surveillance frequencies.
Similarly, there is no impact tosafety analysis acceptance criteria as described in the plant licensing basis. To evaluatea change in the relocated surveillance frequency, FPL will perform a probabilistic riskevaluation using the guidance contained in NRC-approved NEI 04-10, Revision 1 inaccordance with the TS Surveillance Frequency Control Program.
NEI 04-10,Revision 1, methodology provides reasonable acceptance guidelines and methods forevaluating the risk increase of proposed changes to surveillance frequencies consistent with Regulatory Guide (RG) 1.177, An Approach for Plant-Specific Risk-Informed Decision-Making:
Technical Specifications.
Therefore, the proposed changes do not involve a significant reduction in a margin ofsafety.Based upon the discussion above, FPL concludes that the requested change does not involve asignificant hazards consideration as set forth in 10 CFR 50.92(c),
Issuance of Amendment.
Page 3 of 3 Turkey Point Units 3 and 4 L-2014-033 Docket Nos. 50-250 and 50-251 Attachment 6Attachment 6Turkey Point Nuclear PlantLicense Amendment Request No. LAR-229Cross-Reference Between TSTF-425and Turkey Point Technical Specifications Page 1 of 13 Turkey Point Units 3 and 4Docket Nos. 50-250 and 50-251L-2014-033 Attachment 6TSTF-425 Turkey PointSurveillance Requirements Surveillance Surveillance Requirement Requirement 3.1 Reactivity Control Systems3.1.1, Shutdown Margin (SDM)Verify SDM to be within limits specified in the COLR. SR 3.1.1.1 -----When in MODES I or 2 with keffrr1 ... control bank 4.1.1.1.1.b withdrawal is within limits of specification 3.1.3.6.When in MODES 3 or 4, .-. consideration of the following 4.1.1.1.1
.efactors:SDM hall be determined to be within limit ... by 4.1.1.2.b consideration of the following factors:3.1.2, Core Reactivity Verify measured core reactivity is within +/-1% Ak/k of p vSR 3.1.2.1 41112predicted values._______________________
______________________
3.1.4, Rod Group Alignment LimitsVerify individual rod positions within alignment limit. SR 3.1.4.1 4.1.3.1.1 Verify rod freedom of movement by moving each rod not SR 3.1.4.2 4.1.3.1.2 fully inserted in the core >10 steps in either direction.
Verify demand position indicating system and analog ----- 4.1.3.2.1 position indicating system agree within allowable deviation.
Perform channel check, channel calibration and analog 4.1.3.2.2 channel operational test -individual rod position.
Table 4.1-1Channel check and analog channel operational test -4.1.3.2.2 demand position.
Table 4.1-1Verify group demand position indicator operable by 4.1.3.3.1 movement of associated control rod.Verify rod drop time of full length rods ----- 4.1.3.4.c 3.1.5, Shutdown Bank Insertion LimitsVerify each shutdown bank is within the insertion limit I SR 3.1.5.1 4.1.3.5.b specified in the COLR. I3.1.6, Control Bank Rod Insertion LimitsVerify each control bank position is within the limits specified SR 3.1.6.2 4.1.3.6in the COLRVerify sequence and overlap limits specified in the COLR SR 3.1.6.3are met for control banks not fully withdrawn from the core.3.1.8, Physics Test Exceptions
-MODE 2Verify RCS lowest loop temperature
>[531]OF.
SR 3.1.8.2 4.10.3.3Verify thermal power is < 5% RTP. SR 3.1.8.3 4.10.3.1Verify SDM within limits specified in the COLR. SR 3.1.8.4 4.10.1.1TURKEY POINT TECHNICAL SPECIFICATIONS 3/4.1.2, Boration System -Flowpath
-ShutdownVerify each valve in the flow path that is not locked, sealed, -.or otherwise secured in position is in correct position.
4 1 2.1.bPage 2 of 13 Turkey Point Units 3 and 4Docket Nos. 50-250 and 50-251L-2014-033 Attachment 6TSTF-425 Turkey PointSurveillance Requirements Surveillance Surveillance Requirement Requirement 3/4.1.2, Boration System -Flowpath
-Operating Verify each valve in the flow path that is not locked, sealed, --------
4.1.2.2.b or otherwise secured in position is in correct position.
_Verify the flowpath
... delivers at least 16 gpm to the RCS. -- .... 14.1.2.2.c 3/4.1.2, Boration System -Borated Water Sources -ShutdownVerify boron concentration.
----- .4.1.2.4.a.
1Verify indicated borated water volume. ----- .4.1.2.4.a.2 Verify temperature of boric acid tanks room >_620F, when it is- ------ 4.1.2.4.a.3 source of borated water3/4.1.2, Boration System -Borated Water Sources -Operating Verify boron concentration.
----- .4.1.2.5.a.
1Verify indicated borated water volume. ----- .4.1.2.5.a.2 Verify temperature of boric acid tanks room >620F, when it is- ------ 4.1.2.5.a.3 source of borated water3.2 Power Distribution Limits3.2.1, Heat Flux Hot Channel FactorVerify Fc%(Z) are within limits SR 3.2.1.1 4.2.2.1.d.2 Determine Fj(Z) using Moveable Incore Detectors
----- 4.2.2.2.b.1 Update flux map ----- 4.2.2.2.c.3 3.2.2, Nuclear Enthalpy Rise Hot Channel FactorVerify FNAH is within limits SR 3.2:2.1 J 4.2.3.3.b 3.2.3, Axial Flux Difference Verify AFD within limits SR 3.2.3.1 4.2.1.1.a.1 Determine target flux difference
----- 4.2.1.2Update target flux difference
----- 4.2.1.33.2.4, Quadrant Power Tilt RatioVerify QPTR within limits by calculation F SR 3.2.4.1 4.2.4.1 aTSTF-425 Turkey PointSurveillance Requirements Surveillance Surveillance Requirement Requirement
 
===3.3 Instrumentation===
3.3.1, Reactor Trip System Instrumentation 4.3.1.1, Table 4.3-1Functional Units -2a, 2b,Perform Channel Check SR 3.3.1.1 3n4 a 5,6,7 , 8 , ,3, 4,5, 6,7, 8, 9,10, 11,12Compare Calorimetric Heat Balance to Power SR 3.3.1.2 4.3.1.1, Table 4.3-1Range Channel -Adjust as necessary Functional Unit -2aIncore Detector validation SR 3.3.1.3 -----Perform Trip Actuating Device Operational Test 4.3.1.1, Table 4.3-1(TADOT) SR 3.3.1.4 Functional Units -18, 19,21Page 3 of 13 Turkey Point Units 3 and 4Docket Nos. 50-250 and 50-251L-2014-033 Attachment 6TSTF-425 Turkey PointSurveillance Requirements Surveillance Surveillance Requirement Requirement 4.3.1.1, Table 4.3-1Perform Actuation Logic Test SR 3.3.1.5 FuncT al Unt-2Functional Unit -20Calibrate excore channels SR 3.3.1.6 4.3.1.1, Table 4.3-1Functional Unit -2a -----4.3.1.1, Table 4.3-1Perform Channel Operational Test (COT) SR 3.3.1.7 Functional Units -2a, 4, 5,6,7, 8,9, 10, 11, 12Perform COT SR 3.3.1.8 -----Perform TADOT SR 3.3.1.9 9----4.3.1. 1, Table 4.3-1Perform Channel Calibration SR 3.3.1.10 Functional Units -9, 10,11, 12, 13, 14, 15a, 15bPerform Channel Calibration 4.3.1.1, Table 4.3-1SR 3.3.1.11 Functional Units -2b, 3, 4,5, 17a, 17b, 17c, 17dPerform Channel Calibration SR 3.3.1.12 4.3.1.1, Table 4.3-1Functional Units -6, 7, 84.3.1.1, Table 4.3-1Perform COT SR 3.3.1.13 Functional Units -17a,17b, 17c, 17dPerform TADOT SR 3.3.1.14 4*3*1*1,Table4.3-1 Functional Units- 1, 16Perform RTS Response Time Test SR 3.3.1.163.3.2, Engineered Safety Feature Actuation System Instrumentation 4.3.2.1, Table 4.3-2Functional Units -ld, le,Perform C hannel C heck SR 3.3.2.1 if, 3c4t -S 6 , 7c,1f, 3c4, 4d, 5c, 6b, 7b, 7c,9c, 9e4.3.2.1, Table 4.3-2Functional Units -1lb, 1lc,Perform Actuation Logic Test SR 3.3.2.2 2a, 2bt 3 b b, 4b,2a, 2b, 3a2, 3b2, 3b3, 4b,4c, 5a, 6aPerform Actuation Logic Test SR 3.3.2.3 -----4.3.2.1, Table 4.3-2Perform Master Relay Test SR 3.3.2.4 Functional Units -lb, 2a,3a2, 3b2, 4b, 5a, 6a4.3.2.1, Table 4.3-2Functional Units -ld, le,Pf, 3c4, 4d, 5c, 6b, 8a, 8b,9c, 9e4.3.2.1, Table 4.3-2Perform Slave Relay Test SR 3.3.2.6 Functional Units -lb, 2a,3a2, 3b2, 4b, 5a, 6a4.3.2.1, Table 4.3-2Perform TADOT SR 3.3.2.7 Functional Units -6d, 7a,7b, 7cPage 4 of 13 Turkey Point Units 3 and 4Docket Nos. 50-250 and 50-251L-2014-033 Attachment 6TSTF-425 Turkey PointSurveillance Requirements Surveillance Surveillance Requirement Requirement 4.3.2.1, Table 4.3-2Functional Units- la, 2b,Perform TADOT SR 3.3 2.8 3al, 3b1, 3b3, 3d, 4a, 4c,6e, 9d4.3.2.1, Table 4.3-2Functional Units -lc, ld,Perform Channel Calibration SR 3.3.2.9 le, if, 2b, 3b3, 3c4, 4c,4d, 5c, 6b, 6d, 7a, 7b, 7c,8a, 8b, 9c, 9ePerform ESFAS Response Time Test SR 3.3.2.103.3.3, Post Accident Monitoring Instrumentation Perform Channel Check SR 3.3.3.1 4.3.3.3, Table 4.3-4Perform Channel Calibration SR 3.3.3.2 4.3.3.3, Table 4.3-43.3.4, Remote Shutdown SystemPerform Channel Check SR 3.3.4.1 -----Verify control circuit and transfer switch SR 3.3.4.2 -----Perform Channel Calibration SR 3.3.4.3 -----Perform TADOT SR 3.3.4.4 -----3.3.5, Loss of Power Diesel Generator Start Instrumentation Perform Channel Check SR 3.3.5.1 ----Perform TADOT SR 3.3.5.2 .....Perform Channel Calibration SR 3.3.5.3 .....3.3.6, Containment Purge and Exhaust Isolation Instrumentation Perform Channel Check SR 3.3.6.1 -----Perform Actuation Logic Test SR 3.3.6.2 -----Perform Master Relay Test SR 3.3.6.3 -----Perform Actuation Logic Test SR 3.3.6.4 -----Perform Master Relay Test SR 3.3.6.5 -----Perform COT SR 3.3.6.6 -----Perform Slave Relay Test SR 3.3.6.7 -----Perform TADOT SR 3.3.6.8 -----Perform Channel Calibration SR 3.3.6.93.3.7, Control Room Emergency Filtration System Actuation Instrumentation Perform Channel Check SR 3.3.7.1 -----Perform COT SR 3.3.7.2 -----Perform Actuation Logic Test SR 3.3.7.3 -----Perform Master Relay Test SR 3.3.7.4 -----Perform Actuation Logic Test SR 3.3.7.5 -----Perform Master Relay Test SR 3.3.7.6 -----Perform Slave Relay Test SR 3.3.7.7 -----Perform TADOT SR 3.3.7.8 -----Perform Channel Calibration SR 3.3.7.9 -----Page 5 of 13 Turkey Point Units 3 and 4Docket Nos. 50-250 and 50-251L-2014-033 Attachment 6TSTF-425 Turkey PointSurveillance Requirements Surveillance Surveillance Requirement Requirement 3.3.8, Fuel Building Air Cleanup System Actuation Instrumentation Perform Channel Check SR 3.3.8.1 -----Perform COT SR 3.3.8.2 -2...Perform Actuation Logic Test SR 3.3.8.3 3----Perform TADOT SR 3.3.8.4 4----Perform Channel Calibration SR 3.3.8.5 -----3.3.9, Boron Dilution Protection SystemPerform Channel Check SR 3.3.9.1 -----Perform COT SR 3.3.9.2Perform Channel Calibration SR 3.3.9.3 -----TURKEY POINT TECHNICAL SPECIFICATIONS 3/4.3.3, Monitoring Instrumentation Radiation Monitoring Instrumentation 4.3.3.1 Table 4.3-3Perform Channel CheckPerform Analog Channel Operational Test ----- 4.3.3.1, Table 4.3-3Perform Channel Calibration
----- 4.3.3.1, Table 4.3-3Normalize moveable incore detectors
----- 4.3.3.2Explosive Gas Monitoring Instrumentation 4.3.3.6, Table 4.3-6Perform Channel CheckPerform Analog Channel Operational Test ----- 4.3.3.6, Table 4.3-6Perform Channel Calibration
----- 4.3.3.6, Table 4.3-6TSTF-425 Turkey PointSurveillance Requirements Surveillance Surveillance Requirement
.Requirement 3.4 Reactor Coolant System3.4.1, RCS Pressure, Temperature, and Flow DNB LimitsVerify pressurizer pressure
> limit in COLR. SR 3.4.1.1 4.2.5.1Verify RCS average temperature
> limit in COLR. SR 3.4.1.2 4.2.5.1Verify RCS total flow rate > limit. SR 3.4.1.3 4.2.5.2Verify RCS flow using precision heat balance SR 3.4.1.4 4.2.5.4Perform Channel Calibration
-RCS flow indicators
----- 4.2.5.33.4.2, RCS Minimum Temperature for Criticality Verify RCS Tavg SR 3.4.2.13.4.3, RCS Pressure and Temperature (PIT) LimitsVerify pressure temperature and heatup and cooldown rates SR 3.4.3.13.4.4, RCS Loops -MODES 1 and 2Verify RCS loops in operation SR 3.4.4.1 4.4.1.13.4.5, RCS Loops -MODE 3Verify RCS loops in operation SR 3.4.5.1 4.4.1.2.3 Verify steam generator secondary side water level SR 3.4.5.2 4.4.1.2.2 Verify correct breaker alignment and power available SR 3.4.5.3 4.4.1.2.1 Page 6 of 13 Turkey Point Units 3 and 4Docket Nos. 50-250 and 50-251L-2014-033 Attachment 6TSTF-425 Turkey PointSurveillance Requirements Surveillance Surveillance Requirement Requirement 3.4.6, RCS Loops -MODE 4Verify RHR or RCS loop in operation SR 3.4.6.1 4.4.1.3.3 Verify steam generator secondary side water level SR 3.4.6.2 4.4.1.3.2 Verify correct breaker alignment and power available SR 3.4.6.3 4.4.1.3.1 3.4.7, RCS Loops -MODE 5 -Loops FilledVerify RHR or RCS loop in operation SR 3.4.7.1 4.4.1.4.1.2 Verify steam generator secondary side water level SR 3.4.7.2 4.4.1.4.1.1 Verify correct breaker alignment and power available SR 3.4.7.33.4.8, RCS Loops -MODE 5 -Loops Not FilledVerify RHR loop in operation SR 3.4.8.1 4.4.1.4.2 Verify correct breaker alignment and power available SR 3.4.8.23.4.9, Pressurizer Verify water level <- [92]% SR 3.4.9.1 4.4.3.1Verify heater capacity SR 3.4.9.2 4.4.3.2Verify heater emergency power supply SR 3.4.9.3 -----3.4.11, Pressurizer Power Operated Relief Valves (PORVs)Cycle PORV block valves SR 3.4.11.1 4.4.4Cycle PORVs SR 3.4.11.2
-----Cycle solenoid air control and check valves SR 3.4.11.3
-----Verify PORV and block valve emergency power supply SR 3.4.11.4
-----3.4.12, Low Temperature Overpressure Protection (LTOP) SystemVerify maximum of one HPSI pump injecting to RCS SR 3.4.12.1 4.4.9.3.3 Verify maximum of one charging pump injecting to RCS SR 3.4.12.2 4.4.9.3.3 Verify ECCS accumulators isolated SR 3.4.12.3 4.4.9.3.3 Verify RHR suction valves open SR 3.4.12.4
-----Verify RCS vent open SR 3.4.12.5 4.4.9.3.2 Verify PORV block valve open SR 3.4.12.6 4.4.9.3.1.c Verify RHR suction isolation valve locked open with power SR 3.4.12.7removedChannel Operational Test -PORV SR 3.4.12.8 4.4.9.3.1.a Channel Calibration
-PORV SR 3.4.12.9 4.4.9.3.1.b Verify backup nitrogen supply 4.4.9.3.1.d 3.4.13, RCS Operational LeakagePerform water inventory balance SR 3.4.13.1 4.4.6.2.1.c Verify primary to secondary leakage SR 3.4.13.2 4.4.6.2.1.e Monitor containment atmosphere
----- 4.4.6.2.1.a Monitor containment sump level ----- 4.4.6.2.1.b Monitor reactor head flange leakoff system ----- 4.4.6.2.1
.d3.4.14, RCS Pressure Isolation Valve (PIV) LeakageVerify PIV leakage SR 3.4.14.1 4.4.6.2.2.a Verify RHR autoclosure interlock prevents valves from SR 3.4.14.2
-openingVerify RHR autoclosure interlock closes valves SR 3.4.14.3
-----Page 7 of 13 Turkey Point Units 3 and 4Docket Nos. 50-250 and 50-251L-2014-033 Attachment 6TSTF-425 Turkey PointSurveillance Requirements Surveillance Surveillance Requirement Requirement 3.4.15, RCS Leakage Detection Instrumentation Perform Channel Check -containment atmosphere SR 3.4.15.1radioactivity monitor 4.4.6.1,Perform Channel Operational Test -containment atmosphere SR 3.4.15.2 Table 4.3-3radioactivity monitorPerform Channel Calibration
-containment sump monitor SR 3.4.15.3 4.4.6.1.b Perform Channel Calibration
-containment atmosphere SR 3.4.15.4 4.4.6.1,radioactivity monitor Table 4.3-3Perform Channel Operational Test -containment air cooler SR 3.4.15.5condensate flow rate monitor3.4.16, RCS Specific ActivityDetermine gross specific activity SR 3.4.16.1 4.4.8, Table 4.4-4Determine Dose Equivalent 1-131 SR 3.4.16.2 4.4.8, Table 4.4-4Determine E-Bar SR 3.4.16.3
-----Tritium determination
----- 4.4.8, Table 4.4-4Determine Dose Equivalent XE-133 ----- 4.4.8, Table 4.4-43.4.17, RCS Loop Isolation ValvesVerify valves open SR 3.4.17.13.4.19, RCS Loops -Test Exceptions Verify Thermal Power > P-7 SR 3.4.19.1
.....TURKEY POINT TECHNICAL SPECIFICATIONS 3/4.4.7, Chemistry Dissolved oxygen, Chloride, Fluoride 4.4.7 , Table 4.4-33/4.4.9.2, RCS VentsVerify vent path 4.4.113.5 Emergency Core Cooling Systems (ECCS)3.5.1, Accumulators Verify isolation valve open SR 3.5.1.1 4.5.1.1.a.3 Verify water volume SR 3.5.1.2 4.5.1.1.a.1 Verify nitrogen cover pressure SR 3.5.1.3 4.5.1.1.a.2 Verify boron concentration SR 3.5.1.4 4.5.1.1.b Verify power removed from isolation valve operator SR 3.5.1.5 4.5.1.1.c Check valve operability
----- 4.5.1.1.
d3.5.2, ECCS -Operating Verify valve positions with power removed SR 3.5.2.1 4.5.2.aVerify flow path valve positions SR 3.5.2.2 4.5.2.b.2 Verify piping full of water SR 3.5.2.3 4.5.2.b.1 Verify valve automatic actuations SR 3.5.2.5 4.5.2.f.1 Verify automatic pump starts SR 3.5.2.6 4.5.2.f.2.a 4.5.2.f.2.b Verify throttle valve positions SR 3.5.2.7 4.5.2.g.2 Inspect containment sump suction inlets SR 3.5.2.8 4.5.2.e.3 RHR Pump IST ----- 4.5.2.b.3 Page 8 of 13 Turkey Point Units 3 and 4Docket Nos. 50-250 and 50-251L-2014-033 Attachment 6TSTF-425 Turkey PointSurveillance Requirements Surveillance Surveillance Requirement Requirement SI Pump IST ----- 4.5.2.c.1 RHR automatic closure interlock
----- 4.5.2.e.
1RWS T isolation from RHR interlock
----- 3.5.2.e.2 3.5.4, Refueling Water Storage Tank (RWST)Verify water temperature SR 3.5.4.1 -----Verify water volume SR 3.5.4.2 4.5.4.a.1 Verify boron concentration SR 3.5.4.3 4.5.4.a.2 3.5.5, Seal Injection FlowVerify throttle valve position SR 3.5.5.1 .3.5.6, Boron Injection TankVerify water temperature SR 3.5.6.1 -----Verify water volume SR 3.5.6.2 -----Verify boron concentration SR 3.5.6.3 -----3.6 Containment Systems3.6.2, Containment Air LocksVerify only one door can be opened SR 3.6.2.2 4.6.1,3.c 3.6.3, Containment Isolation ValvesVerily [42] inch purge valves closed SR 3.6.3.1 4.6.1.7.1 Verily [8] inch purge valves closed SR 3.6.3.2 -----Verify manual isolation valves and blind flanges position SR 3.6.3.3 4.6.1.1.a Verify automatic valve isolation time SR 3.6.3.5 -----Cycle check valves SR 3.6.3.6 -----Perform leakage test on purge valves SR 3.6.3.7 4.6.1.7.2 Verify automatic valve actuations SR 3.6.3.8 4.6.4.2.a 4.6.4.2.b 4.3.4.2.c Cycle check valves SR 3.6.3.9 -----Verify purge valve opening restricted SR 3.6.3.10 4.6.1.7.3 Verify leakage thru shield building bypass paths SR 3.6.3.11
-----3.6.4, Containment PressureVerify pressure SR 3.6.4.1 4.6.1.43.6.5, Containment Air PressureVerify average air temperature SR 3.6.5.1 4.6.1.53.6.6, Containment Spray and Cooling SystemsVerify valve positions SR 3.6.6.1 4.6.2.1.
aOperate cooling train fans SR 3.6.6.2 4.6.2.2.a Verify cooling train cooling water flow SR 3.6.6.3 4.6.2.2.b.2 Verify automatic valves actuate SR 3.6.6.5 4.6.2.1.c.1 Verify automatic containment spray pump starts SR 3.6.6.6 4.6.2.1 .c.2Verify automatic cooling train start SR 3.6.6.7 4.6.2.2.b.1 Verify spray nozzle unobstructed SR 3.6.6.8 4.6.2.1.d 3.6.7, Spray Additive SystemVerify valve positions SR 3.6.7.1Page 9 of 13 Turkey Point Units 3 and 4Docket Nos. 50-250 and 50-251L-2014-033 Attachment 6TSTF-425 Turkey PointSurveillance Requirements Surveillance Surveillance Requirement Requirement Verify tank volume SR 3.6.7.2 -----Verify NaOH concentration SR 3.6.7.3 -----Verify automatic valves actuate SR 3.6.7.4 -----Verify spray additive flow rate SR 3.6.7.5 -----3.6.9, Hydrogen Mixing SystemOperate train .SR 3.6.9.1 -----Verify train flow rate SR 3.6.9.2 -----Verify automatic train start SR 3.6.9.3 -----3.6.11, Iodine Cleanup SystemOperate train SR 3.6.11.1
-----Verify automatic train start SR 3.6.11.3
-----Verify bypass damper can be opened SR 3.6.11.4 4----TURKEY POINT TECHNICAL SPECIFICATIONS 3/4.6.2.3, Recirculation pH Control SystemBuffenng agent baskets in place ... 4.6.2.3.a.
1Buffering agent quantity 4.6.2.3.a.2 3.7 Plant Systems3.7.2, Main Steam Isolation ValvesVerify automatic valve actuation SR 3.7.2.23.7.3, Main Feedwater Isolation Valves (MFIVs) and Main Feedwater Regulation Valves (MFRVs)Verify automatic valve actuation SR 3.7.3.2 4.7.1.7.a.1 3.7.4, Atmospheric Dump Valves (ADVs)Cycle ADVs SR 3.7.4.1Cycle ADV block valves SR 3.7.4.23.7.5, Auxiliary Feedwater (AFW) SystemVerify valve positions SR 3.7.5.1 4.7.1.2.1.a.3 Verify automatic valve actuations SR 3.7.5.3 4.7.1.2.1
.b.1Verify automatic pump starts SR 3.7.5.4 4.7.1.2.1.b.2 Operate steam-driven pump ----- 4.7.1.2.1.a.
1Verify steam-driven pump valve positions
----- 4.7.1.2.1
.a.2Verify power available
----- 4.7.1.2.1.a.4 3.7.6, Condensate Storage Tank (CST)Verify tank level [SR 3.7.6.1 4.7.1.33.7.7, Component Cooling Water (CCW) SystemVerify valve positions SR 3.7.7.1 4.7.2.bVerify automatic valve actuations SR 3.7.7.2 4.7.2.c.1 Verify automatic pump starts SR 3.7.7.3 4.7.2.c.2 Verify capability to remove heat ----- 4.7.2.aVerify CCW interlocks
----- 4.7.2.c.3 3.7.8, Service Water System (SWS)Verify valve positions I SR 3.7.8.1 4.7.3.aVerify automatic valve actuations SR 3.7.8.2 4.7.3.b.1 Page 10 of 13 Turkey Point Units 3 and 4Docket Nos. 50-250 and 50-251L-2014-033 Attachment 6TSTF-425 Turkey PointSurveillance Requirements Surveillance Surveillance Requirement Requirement Verify automatic pump starts SR 3.7.8.3 4.7.3.b.2 Verify SSW interlocks
----- 4.7.3.b.3 3.7.9, Ultimate Heat Sink (UHS)Verify water level SR 3.7.9.1 .....Verify water temperature SR 3.7.9.2 4.7.4Operate cooling tower fans SR 3.7.9.3 -----Verify automatic fan starts SR 3.7.9.4 -----3.7.10, Control Room Emergency Filtration System (CREFS)Operate trains SR 3.7.10.1 4.7.5.bVerify automatic train actuations SR 3.7.10.3 4.7.5.eFilter/Charcoal testing ----- 4.7.5.cPressure drop across HEPAs ----- 4.7.5.d.
1Maintain negative pressure
----- 4.7.5.d.2 Verify kitchen and toilet dampers ----- 4.7.5.f3.7.11, Control Room Emergency Air Temperature Control System (CREATCS)
Verify capability to remove heat I SR 3.7.11.1 4.7.5.a3.7.12, ECCS Pump Room Exhaust Air Cleanup System (PREACS)Operate trains SR 3.7.12.1
-----Verify automatic train actuations SR 3.7.12.3
-----Verify train can maintain negative pressure SR 3.7.12.4
-----Verify filter bypass can be closed SR 3.7.12.5
-----3.7.13, Fuel Building Air Cleanup System (FBACS)Operate trains SR 3.7.13.1
-----Verify automatic train actuations SR 3.7.13.3
-----Verify train can maintain negative pressure SR 3.7.13.4
-----Verify filter bypass can be closed SR 3.7.13.5
.....3.7.12, Penetration Room Exhaust Air Cleanup System (PREACS)Operate trains SR 3.7.14.1
-----Verify automatic train actuations SR 3.7.14.3
-----Verify train can maintain negative pressure SR 3.7.14.4
-----Verify filter bypass can be closed SR 3.7.14.5
-----3.7.15, Fuel Storage Pool Water LevelVerify pool water level SR 3.7.15.1 4.9.113.7.16, Fuel Storage Pool Concentration Verify pool water boron concentration SR 3.7.16.1 4.9.14.137.18, Secondary Specific ActivityDose Equivalent 1-131 SR 3.7.18.1
-----Gross activity determination 4.7.1.4Table 4.7-1TURKEY POINT TECHNICAL SPECIFICATIONS 3/4.7.1.6, Standby Feedwater SystemDemineralized water tank volume 4.7.1.6.1 Page 11 of 13 Turkey Point Units 3 and 4Docket Nos. 50-250 and 50-251L-2014-033 Attachment 6TSTF-425 Turkey PointSurveillance Requirements Surveillance Surveillance Requirement Requirement Operate pumps ----- 4.7.1.6.2 Feed steam generators with pumps ----- 4.7.1.6.3 Operate diesel driven pump ----- 4.7.1.6.4.a Diesel inspection
----- 4.7.1.6.4.b 3/4.7.7, Sealed Source Contamination Test sources in use .4.7.7.2.a 3.8 Electrical Power Systems3.8.1, AC Sources4.8.1.1.1.a Verify correct breaker alignment and indicated power SR 3.8.1.1 4.8.1.1 ..a4.8.1.1.2.a.6 Verify starts from standby conditions SR 3.8.1.2 4.8.1.1.2.a.4 Verify DG is synchronized and loaded SR 3.8.1.3 4.8.1.1.2.a.5 Verify day tank volume SR 3.8.1.4 4.8.1.1.2.a.1 Check for and remove accumulated water SR 3.8.1.5 4.8.1.1.2.c Verify fuel oil transfer system operates SR 3.8.1.6 4.8.1.1.2.b Verify diesel starts from standby condition SR 3.8.1.7 4.8.1.1.2.a.4 Verify transfer of AC power sources SR 3.8.1.8 4.8.1.1.1.b Verify DG rejects a load SR 3.8.1.9 4.8.1.1.2.g.2 Verify DG does not trip on load rejection SR 3.8.1.10 4.8.1.1.2.g.3 Verify on a loss of power signal SR 3.8.1.11 4.8.1.1.2.g.4 Verify on an ESF actuation signal SR 3.8.1.12 4.8.1.1.2.g.5 Verify DG's noncritical automatic trips are bypassed SR 3.8.1.13Verify DG operates for > 24 hours SR 3.8.1.14 4.8.1.1.2.g.7 Verify DG state voltage and frequency SR 3.8.1.15 4.8.1.1.2.g.7 Verify DG synchronizes SR 3.8.1.16 4.8.1.1.2.g.9 Verify ESF overrides test mode SR 3.8.1.17 4.8.1.1.2.g.10 Verify interval between each sequenced load block. SR 3.8.1.18 4.8.1.1.2.g.12 Verify on LOOP with an ESF SR 3.8.1.19 4.8.1.1.2.g.6 Verify simultaneously start SR 3.8.1.20 4.8.1.1.2.h Verify auto-connected loads ----- 4.8.1.1.2.g.8 Verify fuel oil transfer pump transfers oil ----- 4.8.1.1.2.g.
11Verify DG lockout relay ----- 4.8.1.1.2.g.
13Clean fuel oil storage tank ----- 4.8.1.1.2.i.
1Fuel oil system pressure test (Unit 4 only) ----- 4.8.1.1.2.i.2 3.8.3, Diesel Fuel Oil, Lube Oil, and Starting AirVerify fuel oil storage tank volume SR 3.8.3.1 4.8.1.1.2.a.2 Verify lubricating oil inventory SR 3.8.3.2 4.8.1.1.2.a.3 Verify DG air start receiver pressure SR 3.8.3.4 -----Check for and remove accumulated water SR 3.8.3.5 4.8.1.1.2.d 3.8.4, DC Sources -Operating Verify battery terminal voltage SR 3.8.4.1 4.8.2.1.a.2 Verify each battery charge supplies SR 3.8.4.2 4.8.2.1.c.3 Page 12 of 13 Turkey Point Units 3 and 4Docket Nos. 50-250 and 50-251L-2014-033 Attachment 6TSTF-425 Turkey PointSurveillance Requirements Surveillance Surveillance Requirement Requirement Verify battery capacity is adequate SR 3.8.4.3 4.8.2.1.d 3.8.6, Battery Parameters Verify battery float current SR 3.8.6.1 4.8.2.1.a.3 Verify battery pilot cell float voltage SR 3.8.6.2 4.8.2.1.a.1 Verify battery connected cell electrolyte level SR 3.8.6.3 4.8.2.1.a.1 Verify battery pilot cell temperature SR 3.8.6.4 4.8.2.1 .a.1Verify battery connected cell float voltage SR 3.8.6.5 4.8.2.1 .b.1Verify battery capacity
% of the manufacturer's rating SR 3.8.6.6 4.8.2.1.f Verify battery cell temperature
----- 4.8.2.1.b.2 Inspect battery for visible corrosion 4.8.2.1.b.3 Inspect battery for damage or deterioration
----- 4.8.2.1 .c.1Verify cell to cell and terminal connections
----- 4.8.2.1 .c.2Verify battery connection resistance
----- 4.8.2.1.c.4 3.8.7, Inverters
-Operating Verify inverter voltage and alignment SR 3.8.7.13.8.8, Inverters
-ShutdownVerify inverter voltage and alignment SR 3.8.8.13.8.9, Distribution System -Operating Verify breaker alignments and voltage.
SR 3.8.9.1 4.8.3.13.8.10, Distribution System -ShutdownVerify breaker alignments and voltage SR 3.8.10.1 4.8.3.23.9 Refueling Operations 3.9.1, Boron Concentration Verify boron concentration SR 3.9.1.1 4.9.1.23.9.2, Unborated Water Source Isolation ValvesVerify valve positions SR 3.9.2.1 4.9.1.33.9.3, Nuclear Instrumentation Perform Channel Check -Source Range SR 3.9.3.1 4.9.2.aPerform Channel Calibration
-Source Range SR 3.9.3.2 -----Perform Analog Channel Operational Test ----- 4.9.2.c3.9.4, Containment Penetrations Verify penetration status SR 3.9.4.1 4.9.4Verify purge valve actuation SR 3.9.4.2 .....3.9.5, Residual Heat Removal (RHR) and Coolant Circulation
-High Water LevelVerify one RHR loop in operation SR 3.9.5.1 4.9.8.1.1 Perform Channel Calibration
-RHR flow indicator I ----- 4.9.8.1.2 3.9.6, Residual Heat Removal (RHR) and Coolant Circulation
-Low Water LevelVerify one RHR loop in operation SR 3.9.6.1 4.9.8.2Verify breaker alignment and power available SR 3.9.6.2 .....3.9.7, Refueling Cavity Water LevelVerify refueling cavity level SR 3.9.7.1 4.9.10Page 13 of 13}}

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