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| ~ ARNOLD February 23, 2011 NG-11-0037 10 CFR 50.90 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Duane Arnold Energy Center Docket No. 50-331 Renewed Op. License No. DPR-49 License Amendment Request (TSCR-120): Application for Technical Specification Change Regarding Risk-Informed Justification for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program (TSTF-425, Rev. 3)
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| Pursuant to 10 CFR 50.90, NextEra Energy Duane Arnold, LLC (hereafter NextEra Energy Duane Arnold) hereby requests revision to the Technical Specifications (TS) for the Duane Arnold Energy Center (DAEC).
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| The proposed amendment would modify the DAEC TS by relocating specific surveillance frequencies to a licensee-controlled program with the implementation of Nuclear Energy Institute (NEI) 04-10 (Rev. 1), "Risk-Informed Technical Specification Initiative 58, Risk-Informed Method for Control of Surveillance Frequencies."
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| The changes are consistent with NRC approved Industry Technical Specification Task Force (TSTF) change TSTF-425, Revision 3 (ADAMS Accession No. ML090850642).
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| The Federal Register Notice published on July 6,2009 (74 FR 31966) announced the availability of this TS improvement.
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| Attachment 1 provides a description of the proposed change, the requested confirmation of applicability, and plant-specific verifications. Attachment 2 provides documentation of PRA technical adequacy. Attachment 3 provides the existing TS pages marked up to show the proposed change. Attachment 4 provides the proposed TS 8ases changes for information only. Attachment 5 provides a TSTF-425 (NUREG-1433) versus DAEC TS cross-reference. Attachment 6 provides the Proposed No Significant Hazards Consideration determination.
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| NextEra Energy Duane Arnold, LLC, 3277 DAEC Road, Palo, IA 52324
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| Document Control Desk NG-11-0037 Page 2 of 2 NextEra Energy Duane Arnold requests NRC review and approval of the proposed license amendment within one year of this submittal. NextEra Energy Duane Arnold is requesting a 90 day implementation grace period due to the extensive document changes necessary to implement this license amendment.
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| This application has been reviewed by the DAEC Onsite Review Group. A copy of this submittal, along with the 10 CFR 50.92 evaluation of "No Significant Hazards Consideration," is being forwarded to our appointed state official pursuant to 10 CFR 50.91.
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| This letter makes no new commitments or changes to any existing commitments.
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| If you have any questions or require additional information, please contact Steve Catron at 319-851-7234.
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| I declare under penalty of perjury that the foregoing is true and correct.
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| Executed on February 23, 2011 Christopher R. Costanzo Vice President, Duane Arnold Energy Center NextEra Energy Duane Arnold, LLC Attachments: 1 . Description and Assessment
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| : 2. Documentation of PRA Technical Adequacy
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| : 3. Proposed Technical Specification Changes (Mark-ups)
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| : 4. Proposed Technical Specification Bases Changes (Mark-ups, for information only)
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| : 5. TSTF-425 (NUREG-1433) versus DAEC TS Cross-reference
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| : 6. Proposed No Significant Hazards Consideration cc: M. Rasmusson (State of Iowa)
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| Attachment 1 to NG-11-0037 Page 1 of 6 DESCRIPTION AND ASSESSMENT
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| ==1.0 DESCRIPTION==
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| 2.0 ASSESSMENT 2.1 Applicability of Published Safety Evaluation 2.2 Optional Changes and Variations
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| ==3.0 REGULATORY ANALYSIS==
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| 3.1 No Significant Hazards Consideration 3.2 Applicable Regulatory Requirements 3.3 Conclusions
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| ==4.0 ENVIRONMENTAL CONSIDERATION==
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| ==5.0 REFERENCES==
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| Attachment 1 to NG-11-0037 Page 2 of 6
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| ==1.0 DESCRIPTION==
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| The proposed amendment would modify Technical Specifications (TS) by relocating specific surveillance frequencies to a licensee controlled program with the adoption of Technical Specification Task Force (TSTF)-425, Revision 3, "Relocate Surveillance Frequencies to Licensee Control - Risk Informed Technical Specification Task Force (RITSTF) Initiative 5." Additionally, the change would add a new program, the Surveillance Frequency Control Program, to TS Section 5.0, "Administrative Controls."
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| The changes are consistent with NRC approved Industry/TSTF Standard Technical Specifications (STS) change TSTF-425, Revision 3 (ADAMS Accession No. ML090850642). The Federal Register Notice published on July 6, 2009 (74 FR 31966) announced the availability of this TS improvement.
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| 2.0 ASSESSMENT 2.1 Applicability of Published Safety Evaluation NextEra Energy Duane Arnold has reviewed the safety evaluation dated July 6, 2009. This review included a review of the NRC staffs evaluation, TSTF-425, Revision 3, and the requirements specified in NEI 04-10, Rev. 1, (ADAMS Accession No. ML071360456). includes NextEra Energy Duane Arnolds documentation with regard to PRA technical adequacy consistent with the requirements of Regulatory Guide 1.200, Revision 1 (ADAMS Accession No. ML070240001),
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| Section 4.2, and describes any PRA models without NRC-endorsed standards, including documentation of the quality characteristics of those models in accordance with Regulatory Guide 1.200.
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| NextEra Energy Duane Arnold has concluded that the justifications presented in the TSTF proposal and the safety evaluation prepared by the NRC staff are applicable to DAEC and justify this amendment to incorporate the changes to the DAEC TS.
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| 2.2 Optional Changes and Variations The proposed amendment is consistent with the STS changes described in TSTF-425, Revision 3, however, NextEra Energy Duane Arnold proposes variations or deviations from TSTF-425, as identified below.
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| : 1. Revised (typed) TS pages are not included in this amendment request given the number of TS pages affected, the straightforward nature of the
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| Attachment 1 to NG-11-0037 Page 3 of 6 proposed changes, and other pending NextEra Energy Duane Arnold license amendment requests that impact some of the same TS pages.
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| Providing only mark-ups of the proposed TS changes satisfies the requirements of 10 CFR 50.90 in that the mark-ups fully describe the changes desired. This represents an administrative deviation from the NRC staff's model application dated July 6, 2009 (74 FR 31996) with no impact on the NRC staff's model safety evaluation published in the same Federal Register Notice. As a result of this deviation, the contents and numbering of the attachments for this amendment request differ from the attachments specified in the NRC staff's model application. This deviation is consistent with many other industry applications adopting TSTF-425 (Examples, NRC Accession No. ML100480339 and ML100890320).
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| Additionally, the proposed Bases changes are provided in Attachment 3.
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| The proposed changes to the TS Bases are modified from those presented in TSTF-425 and are based upon recent plants submittals and subsequent NRC feedback (ML100990099). The proposed TS Bases changes are provided to the NRC for information only. Changes to the Bases are made in accordance with the DAEC Bases Control Program and, therefore, do not require NRC prior approval.
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| : 2. The definition of STAGGERED TEST BASIS is being relocated from DAEC TS Definitions (Chapter 1) since this terminology will only be mentioned in one place in the DAEC TS after the adoption of TSTF- 425.
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| The definition is moved to TS Section 5.5.13, "Control Building Envelope Habitability Program," as a footnote. Surveillances contained in TS 5.5.13 were not the subject of TSTF-425 and are not proposed to be otherwise changed. This represents an administrative deviation from TSTF425 with no impact on the NRC staff's model safety evaluation dated July 6, 2009 (74 FR 31996).
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| : 3. Attachment 5 provides a cross-reference between the NUREG-1433 Surveillance Requirements (SRs) included in TSTF-425 versus the DAEC SRs included in this LAR. Attachment 5 includes a summary description of the referenced TSTF-425 (NUREG- 1433)/DAEC TS SRs which is provided for information purposes only and is not intended to be a verbatim description of the TS SRs. This cross-reference highlights the following:
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| : a. NUREG-1433 SRs included in TSTF-425 and corresponding DAEC SRs with identical SR numbers;
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| Attachment 1 to NG-11-0037 Page 4 of 6
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| : b. NUREG-1433 SRs included in TSTF-425 and corresponding DAEC SRs with differing SR numbers;
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| : c. NUREG-1433 SRs included in TSTF-425 that are not contained in the DAEC TS; and,
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| : d. DAEC plant-specific SRs that are not contained in NUREG-1433, and therefore, are not included in the TSTF-425 mark-ups.
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| Concerning the above, DAEC SRs that have SR numbers identical to the corresponding NUREG-1433 SRs are not deviations from TSTF-425.
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| DAEC SRs with SR numbers that differ from the corresponding NUREG-1433 SRs are administrative deviations from TSTF-425 with no impact on the NRCs model SE dated July 6, 2009 (74 FR 31996).
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| For NUREG-1433 SRs that are not contained in the DAEC TS, the corresponding NUREG-1433 mark-ups included in TSTF-425 for these SRs are not applicable to DAEC. This is an administrative deviation from TSTF-425 with no impact on the NRCs model SE dated July 6, 2009 (74 FR 31996).
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| For DAEC plant-specific SRs that are not contained in NUREG-1433, and therefore, are not included in the NUREG-1433 mark-ups provided in TSTF-425, NextEra Energy Duane Arnold has determined that the relocation of the Frequencies for these DAEC plant-specific SRs is consistent with the intent of TSTF-425, Revision 3, and with the NRC's model SE dated July 6, 2009 (74 FR 31996), including the scope exclusions identified in Section 1.0, "Introduction," of the model SE, because the subject plant-specific SRs involve fixed periodic Frequencies. In accordance with TSTF-425, changes to the Frequencies for these SRs would be controlled under the SFCP. The SFCP provides the necessary administrative controls to require that SRs related to testing, calibration and inspection are conducted at a frequency to assure that the necessary quality of systems and components is maintained, that facility operation will be within Safety Limits, and that the Limiting Conditions for Operation will be met. Changes to Frequencies in the SFCP would be evaluated using the methodology and probabilistic risk guidelines contained in Nuclear Energy Institute (NEI) 04-10, Revision 1, "Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies,'' April 2007 (ADAMS Accession Number: ML071360456),
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| as approved by NRC letter dated September 19, 2007 (ADAMS Accession No. ML072570267).
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| Attachment 1 to NG-11-0037 Page 5 of 6 The NEI 04-10 methodology includes qualitative considerations, risk analyses, sensitivity studies and bounding analyses, as necessary, and recommended monitoring of the performance of systems, components, and structures (SSCs) for which Frequencies are changed to assure that reduced testing does not adversely impact the SSCs. In addition, the NEI 04-10, Revision 1 methodology satisfies the five key safety principles specified in Regulatory Guide 1.177, An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications, dated August 1998 (ADAMS Accession No. ML003740176), relative to changes in Surveillance Frequencies.
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| : 4. NextEra Energy Duane Arnold is also making another administrative change in the DAEC TS from those presented in TSTF-425. Specifically, the DAEC TS have been consolidated for those Surveillances that become duplicative once the specific Frequency has been replaced with the reference to the Surveillance Frequency Control Program.
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| For example, TS Section 3.3.1.1 (RPS Instrumentation) currently contains 3 Surveillances to Perform a Channel Functional Tests, one on a 7 day Frequency (SR 3.3.1.1.5), one on a 92 day Frequency (SR 3.3.1.1.9), and one on a 24 month Frequency (SR 3.3.1.1.13). NextEra Energy Duane Arnold proposes to consolidate these 3 Surveillances into the single Surveillance, SR 3.3.1.1.5, with the specified Frequency of In accordance with the Surveillance Frequency Control Program, and to delete existing SR 3.3.1.1.9 and SR 3.3.1.1.13.
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| Such consolidation also changes the numbering of other Surveillances within the same Section, and their cross-reference citations in the corresponding Tables, such as Table 3.3.1.1-1 for RPS Instrumentation.
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| These changes are included in the descriptions in Attachment 5.
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| These changes are deemed administrative in nature, as no technical requirement has been changed, other than the approved change under TSTF-425 to replace the specified Frequency with the citation to the Surveillance Frequency Control Program.
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| ==3.0 REGULATORY ANALYSIS==
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| 3.1 No Significant Hazards Consideration NextEra Energy Duane Arnold has reviewed the proposed No Significant Hazards Consideration Determination (NSHCD) published in the Federal
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| Attachment 1 to NG-11-0037 Page 6 of 6 Register on July 6, 2009, 74 FR 31996 - 32006. NextEra Energy Duane Arnold has concluded that the proposed NSHCD presented in the Federal Register notice is applicable to the DAEC and is provided as Attachment 6 to this amendment request, which satisfies the requirements of 10 CFR 50.91(a).
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| 3.2 Applicable Regulatory Requirements A description of the proposed changes and their relationship to applicable regulatory requirements is provided in TSTF-425, Revision 3 (ADAMS Accession No. ML090850642) and the NRCs model SE published in the Notice of Availability dated July 6, 2009 (74 FR 31996). NextEra Energy Duane Arnold has concluded that the relationship of the proposed changes to the applicable regulatory requirements presented in the Federal Register is applicable to the DAEC.
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| 3.3 Conclusions In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commissions regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.
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| Attachment 2 to NG-11-0037 Page 1 of 35 Documentation of PRA Technical Adequacy TABLE OF CONTENTS Section Page 2.1 Overview.............................................................................................1 2.2 Technical Adequacy of the PRA Model. ............................................4 2.2.1 Plant Changes Not Yet Incorporated Into the PRA Model ....................5 2.2.2 Applicability of Peer Review Findings and Observations ......................6 2.2.3 Consistency with Applicable PRA Standards........... ......... . ................7 2.2.4 Identification of Key Assumptions .......................................................30 2.3 External Events Considerations ...................................................... 30 2.4 Summary ...................................................................................................31 2.5 References ................................................................................................32
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| Attachment 2 to NG-11-0037 Page 2 of 35 Documentation of PRA Technical Adequacy 2.1 Overview The implementation of the Surveillance Frequency Control Program (also referred to as Technical Specifications Initiative 5b) at Duane Arnold Energy Center (DAEC) will follow the guidance provided in NEI 04-10, Revision 1 [Ref. 1] in evaluating proposed surveillance test interval (STI; also referred to as "surveillance frequency") changes.
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| The following steps of the risk-informed STI revision process are common to proposed changes to all STls within the proposed licensee-controlled program.
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| o Each STI revision is reviewed to determine whether there are any commitments made to the NRC that may prohibit changing the interval. If there are no related commitments, or the commitments may be changed using a commitment change process based on NRC endorsed guidance, then evaluation of the STI revision would proceed. If a commitment exists and the commitment change process does not permit the change, then the STI revision would not be implemented.
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| o A qualitative analysis is performed for each STI revision that involves several considerations, including establishing the performance basis for the change, as explained in NEI 04-10, Revision 1.
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| o Each STI revision is reviewed by an Expert Panel, referred to as the Integrated Decision-making Panel (IDP), which is normally the same panel as is used for Maintenance Rule implementation, but with the addition of specialists with experience in surveillance tests and system or component reliability. If the IDP approves the STI revision, the change is documented and implemented, and available for audit by the NRC. If the IDP does not approve the STI revision, the STI value is left unchanged.
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| o Performance monitoring is conducted as recommended by the IDP. In some cases, no additional monitoring may be necessary beyond that already conducted under the Maintenance Rule. The performance monitoring helps to confirm that no failure mechanisms related to the revised test interval become important enough to alter the information provided for the justification of the interval changes.
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| o The IDP is responsible for periodic review of performance monitoring results. If it is determined that the time interval between successive performances of a surveillance test is a factor in the unsatisfactory performances of the surveillance, the IDP returns the STI back to the previously acceptable STI.
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| o In addition to the above steps, the Probabilistic Risk Assessment (PRA) is used when possible to quantify the effect of a proposed individual STI revision compared to acceptance criteria in NEI 04-10. Also, the cumulative impact of all risk-informed STI revisions on all PRAs (i.e., internal events, external events and shutdown) is also compared to the risk acceptance criteria as delineated in NEI 04-10.
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| Attachment 2 to NG-11-0037 Page 3 of 35 Documentation of PRA Technical Adequacy For those cases where the STI cannot be modeled in the plant PRA (or where a particular PRA model does not exist for a given hazard group), a qualitative or bounding analysis is performed to provide justification for the acceptability of the proposed test interval change.
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| The NEI 04-10 methodology endorses the guidance provided in Regulatory Guide 1.200, Revision 1 [Ref. 2], "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-lnformed Activities." The guidance in RG-1.200 Rev. 1 indicates that the following steps should be followed when performing PRA assessments:
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| (NOTE: Because of the broad scope of potential Initiative 5b applications and the fact that the risk assessment details will differ from application to application, each of the issues encompassed in Items 1 through 3 below will be covered with the preparation of each individual PRA assessment made in support of the individual STI interval requests. Item 3 satisfies one of the requirements of Section 4.2 of RG 1.200 Rev. 1. The remaining requirements of Section 4.2 are addressed by item 4 below.)
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| : 1. ldentify the parts of the PRA used to support the application
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| - SSCs, operational characteristics affected by the application and how these are implemented in the PRA model
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| - A definition of the acceptance criteria used for the application
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| : 2. ldentify the scope of risk contributors addressed by the PRA model
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| - If not full scope (i.e., internal and external), identify appropriate compensatory measures or provide bounding arguments to address the risk contributors not addressed by the model.
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| : 3. Summarize the risk assessment methodology used to assess the risk of the application
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| - Include how the PRA model was modified to appropriately model the risk impact of the change request.
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| : 4. Demonstrate the Technical Adequacy of the PRA
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| - Identify plant changes (design or operational practices) that have been incorporated at the site, but are not yet in the PRA model and justify why the change does not impact the PRA results used to support the application.
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| - Document peer review findings and observations that are applicable to the parts of the PRA required for the application, and for those that have not yet been addressed justify why the significant contributors would not be impacted.
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| Attachment 2 to NG-11-0037 Page 4 of 35 Documentation of PRA Technical Adequacy
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| - Document that the parts of the PRA used in the decision are consistent with applicable standards endorsed by the Regulatory Guide (currently, in RG-1.200 Revision 1 this is just the internal events PRA standard). Provide justification to show that where specific requirements in the standard are not adequately met, it will not unduly impact the results.
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| - ldentify key assumptions and approximations relevant to the results used in the decision-making process.
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| The purpose of the remaining portion of this attachment is to address the requirements identified in item 4 above.
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| 2.2 Technical Adequacy of the PRA Model Revision 6 of the DAEC PRA model is being finalized, and will represent the evaluation of the risk profile at DAEC for internal event challenges. The DAEC PRA modeling is highly detailed, including a wide variety of initiating events, modeled systems, operator actions, and common cause events. The PRA model quantification process used for the DAEC PRA is based on the event tree / fault tree methodology, which is a well-known methodology in the industry.
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| NextEra Energy Duane Arnold, LLC (NextEra Energy Duane Arnold) employs a multi-faceted approach to establishing and maintaining the technical adequacy and plant fidelity of the PRA models for the Duane Arnold nuclear plant. This approach includes both procedures for the PRA model maintenance and update process, and the use of self-assessments and independent peer reviews. The following information describes this approach as it applies to the DAEC PRA.
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| PRA Maintenance and Update The NextEra Energy Duane Arnold risk management process ensures that the applicable PRA model is an accurate reflection of the as-built and as-operated plant. This process is defined in the NextEra Energy Duane Arnold Risk Management program, which consists of a governing procedure (ACP 1202.3, "PROBABILISTIC RISK ASSESSMENT (PRA)
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| PROGRAM REQUIREMENTS") and subordinate implementation procedures (Probabilistic Safety Assessment Guidelines (PSAG)). NextEra Energy Duane Arnold procedure PSAG-002, "PRA Model Maintenance and Update," delineates the responsibilities and guidelines for updating the full power internal events PRA model of the Duane Arnold nuclear plant. The overall NextEra Energy Duane Arnold Risk Management program, including PSAG-002, defines the process for implementing regularly scheduled and interim PRA model updates, for tracking issues identified as potentially affecting the PRA models (e.g., due to changes in the plant, industry operating experience, etc.). To ensure that the current PRA model remains an accurate reflection of the as-built, as-operated plants, the following activities are routinely performed:
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| Attachment 2 to NG-11-0037 Page 5 of 35 Documentation of PRA Technical Adequacy o Design changes and procedure changes are reviewed for their impact on the PRA model.
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| o Plant specific initiating event frequencies, failure rates, and maintenance unavailabilities are updated approximately every five years.
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| In addition to these activities, NextEra Energy Duane Arnold risk management procedures provide the guidance for particular risk management maintenance activities. This guidance includes:
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| o Documentation of the PRA model, PRA products, and bases documents.
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| o Guidelines for updating the full power, internal events PRA models for NextEra Energy Duane Arnold nuclear generation sites.
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| o Guidance for use of quantitative and qualitative risk models in support of the On-Line Work Control Process Program for risk evaluations for maintenance tasks (corrective maintenance, preventive maintenance, minor maintenance, surveillance tests and modifications) on systems, structures, and components (SSCs) within the scope of the Maintenance Rule (10 CFR 50.65(a)(4)).
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| The NextEra Energy Duane Arnold risk management process is being enhanced and will be implemented prior to issuing the R.G 1.200 Rev.1 conforming model to include:
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| o Identifying significant maintenance unavailability changes at DAEC and determining CDF impact.
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| o Controlling the model and associated computer files for the base model and the model variations used for risk informed activities and applications.
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| o Implement methods for monitoring of changes in PRA technology and industry experience that could change the results of the PRA.
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| o Implement improved methods to control computer codes used to support applications.
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| o Incorporate a process to evaluate changes on previously implemented risk-informed decisions as part of a model implementation including developing a list of supported applications.
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| o Development of a new Fire PRA model in anticipation of transitioning to NFPA 805
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| [Ref.23].
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| Attachment 2 to NG-11-0037 Page 6 of 35 Documentation of PRA Technical Adequacy In accordance with this guidance, regularly scheduled PRA model updates nominally occur on an approximately 5-year cycle; longer intervals may be justified if it can be shown that the PRA continues to adequately represent the as-built, as-operated plant.
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| As indicated previously, RG 1.200 also requires that additional information be provided as part of the LAR submittal to demonstrate the technical adequacy of the PRA model used for the risk assessment. Each of these items (plant changes not yet incorporated in to the PRA model, relevant peer review findings, consistency with applicable PRA Standards, and the identification of key assumptions) will be discussed in turn.
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| 2.2.1 Plant Changes Not Yet Incorporated into the PRA Model A PRA model change task is created for issues that are identified that could impact the PRA model. These tasks include the identification of those plant changes that could impact the PRA model.
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| As part of the PRA evaluation for each STI change request, a review of open model change tasks for DAEC will be performed and an assessment of the impact on the results of the application will be made prior to presenting the results of the risk analysis to the IDP. If a nontrivial impact is expected, then this may include the performance of additional sensitivity studies or PRA model changes to confirm the impact on the risk analysis.
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| 2.2.2 Applicability of Peer Review Findings and Observations Several assessments of technical capability have been made, and continue to be planned, for the DAEC PRA models. These assessments are as follows and further discussed in the paragraphs below.
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| o DAEC was the first non-pilot plant to have a PSA Peer Evaluation [Ref. 22] in 1997. The PSA Certification process used a team of experienced PSA and system analysts to provide both an objective review of the PSA technical elements and a subjective assessment based on their PSA experience regarding the acceptability of the PSA elements.
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| o During 2005 and 2006, the DAEC PRA model results were evaluated in the BWR Owners Group PRA cross-comparisons study performed in support of implementation of the mitigating systems performance indicator (MSPI) process.
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| o Following the issuance of the ASME PRA Standard and its endorsement by the NRC in R.G. 1.200 Rev. 1, DAEC undertook a detailed self assessment [Ref. 20]
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| of the DAEC PRA model and documentation in preparation for the BWROG PRA Peer review in the fall of 2007. This review was performed using the NEI recommended self-assessment process as endorsed by the NRC in RG 1.200, Rev. 1.
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| Attachment 2 to NG-11-0037 Page 7 of 35 Documentation of PRA Technical Adequacy o In December 2007 a peer review was held at the NextEra Energy offices in Juno Beach, FL, under the auspices of the BWROG, using the NEI 05-04 PRA Peer Review process and the ASME PRA Standard ASME RA-Sb-2005 [Ref. 4] (along with the NRC clarifications provided in Regulatory Guide 1.200, Rev. 1 [Ref. 5].).
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| The 2007 DAEC PRA Peer Review was a full-scope review of all the Technical Elements of the internal events, at-power PRA. The BWROG peer review final report (DUANE ARNOLD ENERGY CENTER: PRA Peer Review Report Using ASME PRA Standard Requirements) was issued in May 2008 [Ref. 21].
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| A PRA model update was started in 2009 and is scheduled to be completed in 2011 to support the DAEC NFPA 805 submittal. This update (Revision 6) addresses the gaps described in the December 2007 peer review. The gap analysis is expected to be updated to reflect pertinent changes to both the ASME PRA Standard and Regulatory Guide 1.200 rev. 1, through a focused PRA Peer Review that is currently scheduled to support the NFPA 805 submittal.
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| A summary of the disposition of the 1997 lndustry PRA Peer Review facts and observations (F&Os) for the DAEC PRA model was documented as part of the statement of PRA capability for MSPl in the DAEC MSPl Basis Document [Ref. 6]. Also the BWROG cross-comparison study noted the fact that, after allowing for plant specific features, there were no MSPI cross-comparison outliers for DAEC.
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| A Gap Analysis for the DAEC PRA 5C model was completed in December 2007 with the final report being issued in May 2008. The 2007 DAEC PRA Peer Review was a full-scope review of all the technical elements of the internal events, at-power PRA. This Gap Analysis was performed against PRA Standard RA-Sb-2005 [Ref. 4] and associated NRC comments in Regulatory Guide 1.200 Revision 1 [Ref. 5]. This gap analysis defined a list of 83 supporting requirements from the Standard for which potential gaps to Capability Category II of the Standard were identified.
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| To address the gaps from the 2007 peer review a project plan was created to upgrade the PRA model in order to support a NFPA 805 submittal. The PRA model upgrade, when finalized, will result in Revision 6 of the updated model. The key focus of this model upgrade is to provide an updated PRA model for use in development of an updated DAEC Fire PRA (using guidance contained in NUREG/CR-6850) to support the DAEC submittal for NFPA 805 (risk informed fire protection). Although not key for this application, a Fire PRA Peer Review was conducted in 2010 on the DAEC Fire PRA model to support the NFPA 805 submittal. The subsequent facts and observations from the Fire PRA Peer Review will be resolved prior to implementation of Revision 6 to again support the NFPA 805 submittal currently scheduled for mid year of 2011.
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| Following this upgrade to the internal events model, a focused Peer Review is scheduled to assess the status of the gap analysis relative to the internal events model.
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| Attachment 2 to NG-11-0037 Page 8 of 35 Documentation of PRA Technical Adequacy 2.2.3 Consistency with Applicable PRA Standards As indicated above, a PRA model update is scheduled to be finalized, resulting in the Revision 6 updated model. In updating the PRA, changes were made to the PRA to address most of the identified gaps, as well as to address other open PRA model change tasks. The revision of the DAEC PRA that will be used for this application will conform to the ASME Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications [Ref. 8] as endorsed by R.G. 1.200 Rev. 1 [Ref. 2].
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| All remaining gaps will be reviewed for consideration during the model update process but are judged to have low impact on the PRA model or its ability to support a full range of PRA applications. The remaining gaps are documented by model change tasks and are contained in a database so that they can be tracked and their potential impacts accounted for in applications where appropriate.
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| Each item will be reviewed as part of each STI change assessment that is performed and an assessment of the impact on the results of the application will be made prior to presenting the results of the risk analysis to the IDP. If a non-trivial impact is expected, then this may include the performance of additional sensitivity studies or PRA model changes to confirm the impact on the risk analysis.
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| Attachment 2 to NG-11-0037 Page 9 of 35 Documentation of PRA Technical Adequacy TABLE 2-1 STATUS OF IDENTIFIED GAPS TO CAPABILITY CATEGORY II OF THE ASME PRA STANDARD ASME Capability IMPORTANCE TO DESCRIPTION OF GAP CURRENT STATUS / COMMENT SRs* Assessment APPLICATION SC-A6 SR Not Met Cannot find proof that bases for the The DAEC Success Criteria Notebook and MAAP runs can be upgraded at the success criteria are consistent with MAAP Notebooks have been updated to time of the Surveillance Frequency the features, procedures, and incorporate MAAP runs performed for the EPU evaluation if deemed necessary.
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| operating philosophy of the plant. LAR as well as runs for the PRA update. The PRA update involved performance of additional MAAP runs to support the LOCA and SBO event tree modifications for the update. The additional MAAP runs were performed with the same version 3 of MAAP as the original MAAP cases.
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| Update of all existing MAAP runs to use the latest revision of MAAP has not been performed. Such an effort is deferred at this time. Update of the DAEC MAAP runs to MAAP4 is not expected to result in significant changes to PRA system or functional success criteria.
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| * The ASME SR refers to the support requirements found in ASME RA-Sb-2005 [Ref 9] , as endorsed by Regulatory Guide 1.200 Rev. 1."[Ref.4].
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| Attachment 2 to NG-11-0037 Page 10 of 35 Documentation of PRA Technical Adequacy TABLE 2-1 STATUS OF IDENTIFIED GAPS TO CAPABILITY CATEGORY II OF THE ASME PRA STANDARD ASME Capability IMPORTANCE TO DESCRIPTION OF GAP CURRENT STATUS / COMMENT SRs* Assessment APPLICATION IF-B3 SR Not Met Table 3.3-1 "Potential Flooding The internal flooding analysis was extensively Itemizing the temperature and Sources in the Control Room" updated and is documented in the updated pressure range of each potential identifies the System and flow rate. Internal Flooding Analysis Notebook. Flow flooding source would not affect the Table 2.2 identifies system and tank rates as a function of breach type are use of the PRA model for the capacities and also identifies ranges documented and flood propagation is purposes of this application. The of flow rates. The internal flooding documented. consideration of the temperature and does not identify the type of breach, pressure sources in the current or the pressure and temperature of The temperature and pressure of the sources flooding analysis adequately the source. are considered in the analysis (e.g., HELB addresses this SR for the purposes effects are considered for the appropriate of this application.
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| sources, such as FW).
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| The specific temperature and pressure range of each source is not itemized in the documentation.
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| * The ASME SR refers to the support requirements found in ASME RA-Sb-2005 [Ref 9] , as endorsed by Regulatory Guide 1.200 Rev. 1."[Ref.4].
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| Attachment 2 to NG-11-0037 Page 11 of 35 Documentation of PRA Technical Adequacy TABLE 2-1 STATUS OF IDENTIFIED GAPS TO CAPABILITY CATEGORY II OF THE ASME PRA STANDARD ASME Capability IMPORTANCE TO DESCRIPTION OF GAP CURRENT STATUS / COMMENT SRs* Assessment APPLICATION QU-D5a SR Met: (CC I) The DAEC PRA model identifies The review team misinterpreted CCII of SR Separately documenting the significant contributors to CDF, such QU-D5a. The ASME Standard does not importance to CDF or LERF from as initiating events, accident require that SSIE fault trees be developed nor, operator actions contained in support sequences, equipment failures, if developed, that they be linked into the system initiating events would not common cause failures, and operator accident sequence models. affect the use of the PRA model for errors in the summary documents of the purposes of this application.
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| the different revisions. For CC II/III, The DAEC PRA includes a loss of River Water the PRA needs do have initiating- initiating event fault tree developed to quantify event fault trees including SSCs and the loss of River Water initiating event operator actions when appropriate, frequency. Other support system initiator so these can be identified in the lists frequencies are estimated using a Bayesian of significant contributors to CDF. statistical update of generic frequencies with DAEC operating experience.
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| Documenting in the PRA base notebooks the importance to overall CDF or LERF from operator actions that may be explicitly modeled or inherent in support system initiating events is deferred at this time and is awaiting industry clarification on the purpose and scope of this enhancement.
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| * The ASME SR refers to the support requirements found in ASME RA-Sb-2005 [Ref 9] , as endorsed by Regulatory Guide 1.200 Rev. 1."[Ref.4].
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| Attachment 2 to NG-11-0037 Page 12 of 35 Documentation of PRA Technical Adequacy TABLE 2-1 STATUS OF IDENTIFIED GAPS TO CAPABILITY CATEGORY II OF THE ASME PRA STANDARD ASME Capability IMPORTANCE TO DESCRIPTION OF GAP CURRENT STATUS / COMMENT SRs* Assessment APPLICATION QU-F3 SR Met: (CC I) Quantification summary provides list Discussions of importance sequences, Expanding the PRA Summary of significant contributors, but does accident classes, and cutsets are included in Notebook discussion to include not provide a detailed description of the updated DAEC PRA Summary Notebook. detailed descriptions of hundreds of such. SR Meet Category I. The level of documentation is judged additional sequences would not affect PROVIDE a detailed description of consistent with the expectations in the PRA the use of the PRA model for the significant accident sequences or Standard. purposes of this application.
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| functional failure groups to satisfy Category II The level of discussion in the PRA Summary Notebook for important sequences is judged reasonable. Providing detailed discussions of hundreds of sequences is judged not an appropriate use of resources for the base PRA and is deferred at this time. Awaiting industry clarification on the purpose and scope of this enhancement.
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| MU-A1 SR Not Met The process does not address a DAEC is currently updating the configuration The upgraded process will be used monitoring of operating procedures, and control procedures to add these for monitoring changes to the as as well as unavailabilities and requirements consistent with industry best operated, as maintained plant. The component failure rate data between practices and NextEra Energy fleet standards. list of changes as a result of this updates. These procedures will be implemented prior to scrutiny will be assessed as part of using the PRA model for quantifying the effect the Surveillance Frequency Control of a proposed individual STI revision. Program.
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| * The ASME SR refers to the support requirements found in ASME RA-Sb-2005 [Ref 9] , as endorsed by Regulatory Guide 1.200 Rev. 1."[Ref.4].
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| Attachment 2 to NG-11-0037 Page 13 of 35 Documentation of PRA Technical Adequacy TABLE 2-1 STATUS OF IDENTIFIED GAPS TO CAPABILITY CATEGORY II OF THE ASME PRA STANDARD ASME Capability IMPORTANCE TO DESCRIPTION OF GAP CURRENT STATUS / COMMENT SRs* Assessment APPLICATION MU-A2 SR Not Met The PRA configuration control DAEC is currently updating the configuration The upgraded process will be used process, as defined in PSAG-2, does and control procedures to add these for monitoring changes to the as not include monitoring of changes in requirements consistent with industry best operated, as maintained plant. The PRA technology and industry practices and NextEra Energy fleet standards. list of changes as a result of this experience that could change the These procedures will be implemented prior to scrutiny will be assessed as part of results of the PRA. using the PRA model for quantifying the effect the Surveillance Frequency Control of a proposed individual STI revision. Program.
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| MU-B1 SR Not Met A change database is maintained. DAEC is currently updating the configuration The upgraded process will be used Changes are not performed in a and control procedures to add these for monitoring changes to the as timely manner. Note: 1997 Peer requirements consistent with industry best operated, as maintained plant. The Review comments addressed in practices and NextEra Energy fleet standards. list of changes as a result of this 2003. The current PRA model These procedures will be implemented prior to scrutiny will be assessed as part of revision is based on a periodic using the PRA model for quantifying the effect the Surveillance Frequency Control update performed in 2003 and the of a proposed individual STI revision. Program.
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| next update has not been scheduled.
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| Note this delay in starting the PRA update was entered into the site's corrective action program.
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| * The ASME SR refers to the support requirements found in ASME RA-Sb-2005 [Ref 9] , as endorsed by Regulatory Guide 1.200 Rev. 1."[Ref.4].
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| Attachment 2 to NG-11-0037 Page 14 of 35 Documentation of PRA Technical Adequacy TABLE 2-1 STATUS OF IDENTIFIED GAPS TO CAPABILITY CATEGORY II OF THE ASME PRA STANDARD ASME Capability IMPORTANCE TO DESCRIPTION OF GAP CURRENT STATUS / COMMENT SRs* Assessment APPLICATION MU-B2 SR Not Met Changes are prioritized in the DAEC is currently updating the configuration The upgraded process will be used Change Database at the start of a and control procedures to add these for monitoring changes to the as PRA update. This supporting requirements consistent with industry best operated, as maintained plant. The requirement requires prioritizing practices and NextEra Energy fleet standards. list of changes as a result of this changes to the PRA model at the These procedures will be implemented prior to scrutiny will be assessed as part of time the changes to the as built, as using the PRA model for quantifying the effect the Surveillance Frequency Control operated plant are discovered. The of a proposed individual STI revision. Program.
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| current methodology does not require documenting the evaluation of impact on past applications that affect plant operation and maintenance. The impact to risk informed decisions should be required by section 4.2 of PSAG-2 and the evaluation documented in the change database.
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| MU-C1 SR Not Met Potential changes to the PRA are DAEC is currently updating the configuration The upgraded process will be used captured in a change database. and control procedures to add these for monitoring changes to the as There is no defined process requirements consistent with industry best operated, as maintained plant. The requirement to evaluate the practices and NextEra Energy fleet standards. list of changes as a result of this cumulative impact of pending These procedures will be implemented prior to scrutiny will be assessed as part of changes. using the PRA model for quantifying the effect the Surveillance Frequency Control of a proposed individual STI revision. Program.
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| * The ASME SR refers to the support requirements found in ASME RA-Sb-2005 [Ref 9] , as endorsed by Regulatory Guide 1.200 Rev. 1."[Ref.4].
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| Attachment 2 to NG-11-0037 Page 15 of 35 Documentation of PRA Technical Adequacy TABLE 2-1 STATUS OF IDENTIFIED GAPS TO CAPABILITY CATEGORY II OF THE ASME PRA STANDARD ASME Capability IMPORTANCE TO DESCRIPTION OF GAP CURRENT STATUS / COMMENT SRs* Assessment APPLICATION MU-E1 SR Not Met The configuration control process DAEC is currently updating the configuration The upgraded process will be used does not specify the testing to be and control procedures to add these for monitoring changes to the as required. Testing has been requirements consistent with industry best operated, as maintained plant. The performed at the discretion of the practices and NextEra Energy fleet standards. list of changes as a result of this model owner. These procedures will be implemented prior to scrutiny will be assessed as part of using the PRA model for quantifying the effect the Surveillance Frequency Control of a proposed individual STI revision. Program.
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| * The ASME SR refers to the support requirements found in ASME RA-Sb-2005 [Ref 9] , as endorsed by Regulatory Guide 1.200 Rev. 1."[Ref.4].
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| Attachment 2 to NG-11-0037 Page 16 of 35 Documentation of PRA Technical Adequacy TABLE 2-1 STATUS OF IDENTIFIED GAPS TO CAPABILITY CATEGORY II OF THE ASME PRA STANDARD ASME Capability IMPORTANCE TO DESCRIPTION OF GAP CURRENT STATUS / COMMENT SRs* Assessment APPLICATION MU-F1 SR Not Met Weakness in most areas have been DAEC is currently updating the configuration The upgraded process will be used noted: and control procedures to add these for monitoring changes to the as requirements consistent with industry best operated, as maintained plant. The (a): PRA inputs, such as revisions to practices and NextEra Energy fleet standards. list of changes as a result of this key operating procedures, are not These procedures will be implemented prior to scrutiny will be assessed as part of reviewed between updates. Ref. F&O using the PRA model for quantifying the effect the Surveillance Frequency Control MU-A1-01. OPEX reviews are not of a proposed individual STI revision. Program.
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| documented. Ref. F&O MU-A2-01.
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| (b) Through (e): The change database provides evidence that a process is active and contains descriptions of changes to the PRA.
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| (f): Record of the process and results used to address the cumulative impact of pending changes. Not met, Reference F&O MU-C1-01).
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| (g): Record of the process and results used to evaluate changes on previously implemented risk-informed decisions (pursuant to MU-D1) Not met, Reference F&O MU-D1-01.
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| (h): Description of the process used to maintain software configuration control. Not met, (Reference MU-F1-01).
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| * The ASME SR refers to the support requirements found in ASME RA-Sb-2005 [Ref 9] , as endorsed by Regulatory Guide 1.200 Rev. 1."[Ref.4].
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| Attachment 2 to NG-11-0037 Page 17 of 35 Documentation of PRA Technical Adequacy TABLE 2-2 DISPOSITION OF PEER REVIEW FINDING F&Os Importance to F&O Discussion Basis and Recommendation Disposition in PRA Update Application SC-A6-01 Cannot find proof that bases for the Success Criteria must represent the as- MAAP runs can be success criteria are consistent with the build, as-operated plant. The DAEC Success Criteria Notebook upgraded at the time of features, procedures, and operating and MAAP Notebooks have been the Surveillance philosophy of the plant. The bases of the During updates, document verification updated to incorporate MAAP runs Frequency evaluation if success criteria is circa 1994 that the success criteria are consistent performed for the EPU LAR as well as deemed necessary.
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| with the current plant. runs for the PRA update. The PRA update involved performance of additional MAAP runs to support the LOCA and SBO event tree modifications for the update. The additional MAAP runs were performed with the same version 3 of MAAP as the original MAAP cases.
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| Conversion to MAAP4 is deferred for future consideration. The PRA Standard does not require a specific revision of the MAAP software or use of the MAAP software. Update of all existing MAAP runs to use the latest revision of MAAP has not been performed. Such an effort is deferred at this time. Update of the DAEC MAAP runs to MAAP4 is not expected to result in significant changes to PRA system or functional success criteria.
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| Attachment 2 to NG-11-0037 Page 18 of 35 Documentation of PRA Technical Adequacy TABLE 2-2 DISPOSITION OF PEER REVIEW FINDING F&Os Importance to F&O Discussion Basis and Recommendation Disposition in PRA Update Application SY-A3-03 No evidence of failure of either vital 4kV Non conservative analysis This failure mode is considered This consideration will bus SUT breaker to trip on LOSP which addressed by the EDG output circuit be evaluated along with would fail associated EDG breaker from Assure that the model includes the breakers and the circuitry signals. any other considered closing onto the bus necessary dependencies for this event Consider in future update to explicitly changes as part of the and that other dependencies are not model these circuit breakers separately. Surveillance Frequency omitted. The key issue is that the fault evaluation involving tree model missed a dependency (i.e., these key components.
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| the failure of the normal supply breaker to each vital 4kV bus to trip upon a loss of offsite power to allow the associated EDG to close onto the bus). More importantly, a common cause failure between the two breakers for the two busses has been missed. This missed CCF would contribute significantly to SBO sequences (has a RAW > 1000 at another plant).
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| Attachment 2 to NG-11-0037 Page 19 of 35 Documentation of PRA Technical Adequacy TABLE 2-2 DISPOSITION OF PEER REVIEW FINDING F&Os Importance to F&O Discussion Basis and Recommendation Disposition in PRA Update Application DA-C10-01 When using surveillance test data, EPIX information used which is plant EPIX information is currently used to The component REVIEW the test procedure to determine specific. No evidence of failure mode support DAEC data gathering for very boundaries, generic, whether a test should be credited for level information is provided. few component failure modes. and site specific data each possible failure mode. COUNT only sources are completed tests or unplanned operational Provide a description documenting the In addition, consistent with Supporting documented in the PRA demands as success for component test data at the level of the modeled Requirement DA-C10 in the PRA Model. The operation. If the component failure mode basic events. Make sure the test data Standard, the collection of plant specific documentation allows is decomposed into sub-elements (or tests the entire component as defined by component failure events and exposures for updating the PRA causes) that are fully tested, then USE the basic event. (i.e., demands or run time hours) model if separately tests that exercise specific sub-elements considers whether the procedures (the modeling a sub-in their evaluation. Thus, one sub- vehicle for generating many of the component within a element sometimes has many more demands, exposures and failure events component boundary is successes than another. [Example: a that are gathered for the data analysis) necessary to perform a diesel generator is tested more frequently properly take into account the component Surveillance Frequency than the load sequencer. IF the boundaries and failure modes that are evaluation.
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| sequencer were to be included in the modeled in the PRA.
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| diesel generator boundary, the number of valid tests would be significantly Detailed discussions of procedure decreased.] aspects and data gathering are not performed for the update. Such a task would be a significant expenditure of resources with no significant benefit.
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| Attachment 2 to NG-11-0037 Page 20 of 35 Documentation of PRA Technical Adequacy TABLE 2-2 DISPOSITION OF PEER REVIEW FINDING F&Os Importance to F&O Discussion Basis and Recommendation Disposition in PRA Update Application IF-B3-01 The internal flooding does not identify the The characterizations of the releases The internal flooding analysis was Not itemizing the type of breach, or the pressure and were not included in the IF Notebook extensively updated and is documented temperature and temperature of the source. Table 3.3-1 in the updated Internal Flooding Analysis pressure range of each "Potential Flooding Sources in the Identify the type of breach, pressure and Notebook. Flow rates as a function of potential flooding source Control Room" identifies the System and temperature of source. breach type are documented as well as would not affect the use flow rate. Table 2.2 identifies plant flood propagation is documented. of the PRA model for systems that could contribute to potential the purposes of this floods and provides tank capacities and The temperature and pressure of the application The ranges of flow rates. sources are considered in the analysis consideration of the (e.g., HELB effects are considered for the temperature and appropriate sources, such as FW). pressure sources in the flooding analysis The specific temperature and pressure adequately addresses range of each source is not itemized and this SR for the purposes is deferred for future consideration. of this application.
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| Inserting specific temperatures and pressure values in this PRA notebook is not considered desirable at this time Awaiting future industry clarification on the use and importance of such an enhancement.
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| Attachment 2 to NG-11-0037 Page 21 of 35 Documentation of PRA Technical Adequacy TABLE 2-2 DISPOSITION OF PEER REVIEW FINDING F&Os Importance to F&O Discussion Basis and Recommendation Disposition in PRA Update Application QU-D5a-01 The DAEC PRA model identifies To reach CCII/III it is necessary to The review team misinterpreted CCII of Separately documenting significant contributors to CDF, such as include in the significance of the SR QU-D5a. The ASME Standard does the importance to CDF initiating events, accident sequences, contributions of SSC and operator not require that SSIE fault trees be or LERF from operator equipment failures, common cause actions, their contributions to both developed nor, if developed, that they be actions contained in failures, and operator errors in the initiating event frequencies and to event linked into the accident sequence support system initiating summary documents of the different mitigation. models. events would not affect revisions. However, the significance of the use of the PRA contributions of SSC/operator actions One possible resolution approach is to The DAEC PRA includes a loss of River model for the purposes associated with systems whose failure model the support system initiating Water initiating event fault tree developed of this application.
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| results in an initiating event was not events as fault trees so that the to quantify the loss of River Water included at the SSC/operator action level. contributing SSCs and operator actions initiating event frequency. Other support appear explicitly in the fault trees. system initiator frequencies are estimated using a Bayesian statistical update of generic frequencies with DAEC operating experience.
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| Documenting in the PRA base notebooks the importance to overall CDF or LERF from operator actions that may be explicitly modeled or inherent in support system initiating events is deferred at this time and is awaiting industry clarification on the purpose and scope of this enhancement.
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| Attachment 2 to NG-11-0037 Page 22 of 35 Documentation of PRA Technical Adequacy TABLE 2-2 DISPOSITION OF PEER REVIEW FINDING F&Os Importance to F&O Discussion Basis and Recommendation Disposition in PRA Update Application QU-F3-01 Quantification summary provides list of Detailed descriptions of significant Separately documenting significant contributors, but does not accident sequences or functions failure Discussions of importance sequences, the importance to CDF prove a detailed description of the groups are required to meet CCII. accident classes, and cutsets are or LERF from operator significant accident sequences or included in the updated DAEC PRA actions contained in functional failure groups. PROVIDE a detailed description of Summary Notebook. The level of support system initiating significant accident sequences or documentation is judged consistent with events would not affect functional failure groups to satisfy the expectations in the PRA Standard. the use of the PRA Category II model for purposes of The level of discussion in the PRA this application.
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| Summary Notebook for important sequences is judged reasonable.
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| Providing detailed discussions of hundreds of sequences is judged not an appropriate use of resources for the base PRA and is deferred at this time.
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| Awaiting industry clarification on the purpose and scope of this enhancement.
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| Attachment 2 to NG-11-0037 Page 23 of 35 Documentation of PRA Technical Adequacy TABLE 2-2 DISPOSITION OF PEER REVIEW FINDING F&Os Importance to F&O Discussion Basis and Recommendation Disposition in PRA Update Application MU-A1-01 The process does not address monitoring The supporting requirement has not been DAEC is currently updating the The upgraded process of operating procedures, as well as met. Changes to operating procedures configuration and control procedures to will be used for monitoring unavailabilities and could have significant impact on HRA add these requirements consistent with monitoring changes to component failure rate data between timing. industry best practices and NextEra the as operated, as updates. Energy fleet standards. maintained plant. The Produce a list of key procedures and These procedures will be implemented list of changes as a review revisions to these procedures. prior to using the PRA model for result of this scrutiny will Consider also reviewing new (revision 0) quantifying the effect of a proposed be assessed as part of procedures for PRA impact. Include individual STI revision. the Surveillance procedures that support important PRA Frequency Control Operator Action. Include Operating Program.
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| Policy guidelines. Consider meeting periodically with operator training personnel to review changes in the focus or execution of training.
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| Periodically (quarterly, or semi-annually) perform a review of Maintenance Rule (a)
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| (1) systems to determine if significant changes in equipment performance has occurred. Note, (a) (1) action plans may result in significant improvement in performance.
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| Document the above reviews under the PRA change database.
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| Attachment 2 to NG-11-0037 Page 24 of 35 Documentation of PRA Technical Adequacy TABLE 2-2 DISPOSITION OF PEER REVIEW FINDING F&Os Importance to F&O Discussion Basis and Recommendation Disposition in PRA Update Application MU-A2-01 The PRA configuration control process, Failure modes identified at other sites DAEC is currently updating the The upgraded process as defined in PSAG-2, does not include and applicable to Duane Arnold are not configuration and control procedures to will be used for monitoring of changes in PRA technology evaluated for PRA impact. Changes in add these requirements consistent with monitoring changes to and industry experience that could PRA technology may not be evaluated industry best practices and NextEra the as operated, as change the results of the PRA. for incorporation in the PRA model. Energy fleet standards. maintained plant. The These procedures will be implemented list of changes as a Evaluate industry OPEX for PRA impact prior to using the PRA model for result of this scrutiny will and document potentially impacts to the quantifying the effect of a proposed be assessed as part of PRA in the change database. Consider individual STI revision. the Surveillance requiring a yearly review of PRA Frequency Control technology changes and document the Program.
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| evaluation in the PRA change database.
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| Technology changes may include such items as, new generic common cause data, a new version of MAAP, etc.
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| The guidance document for the above reviews should provide enough guidance to assure consistent reviews by different individuals.
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| Attachment 2 to NG-11-0037 Page 25 of 35 Documentation of PRA Technical Adequacy TABLE 2-2 DISPOSITION OF PEER REVIEW FINDING F&Os Importance to F&O Discussion Basis and Recommendation Disposition in PRA Update Application MU-B2-01 Changes that would impact risk-informed Changes are prioritized in the Change DAEC is currently updating the The upgraded process decisions are not prioritized at the time of Database at the start of a PRA update. configuration and control procedures to will be used for discovery to ensure that the most This supporting requirement requires add these requirements consistent with monitoring changes to significant changes are incorporated as prioritizing changes to the PRA model at industry best practices and NextEra the as operated, as soon as practical. the time the changes to the as built, as Energy fleet standards. maintained plant. The operated plant are discovered. The These procedures will be implemented list of changes as a current methodology does not require prior to using the PRA model for result of this scrutiny will documenting the evaluation of impact on quantifying the effect of a proposed be assessed as part of past applications that affect plant individual STI revision. the Surveillance operation and maintenance. Frequency Control Program.
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| The impact to risk informed decisions should be required by section 4.2 of PSAG-2 and the evaluation documented in the change database. Prioritize incorporation into the PRA; for example, "Immediate Change Needed," "Next Update," "Future Update" or "No Change Recommended."
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| MU-C1-01 The current configuration control process Potential changes to the PRA are DAEC is currently updating the The upgraded process does not require an evaluation of the captured in a change database. There is configuration and control procedures to will be used for cumulative impact of pending changes. no process requirement to evaluate the add these requirements consistent with monitoring changes to cumulative impact of pending changes, industry best practices and NextEra the as operated, as nor is there evidence this evaluation has Energy fleet standards. maintained plant. The been performed. These procedures will be implemented list of changes as a prior to using the PRA model for result of this scrutiny will Perform a review of pending changes quantifying the effect of a proposed be assessed as part of annually. Update guidance document to individual STI revision. the Surveillance require this review and track in the Frequency Control station's action tracking system. Program.
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| Attachment 2 to NG-11-0037 Page 26 of 35 Documentation of PRA Technical Adequacy TABLE 2-2 DISPOSITION OF PEER REVIEW FINDING F&Os Importance to F&O Discussion Basis and Recommendation Disposition in PRA Update Application MU-E1-01 The PRA configuration control process The configuration control process does DAEC is currently updating the The upgraded process does not include an adequate process for not specify the testing to be required. configuration and control procedures to will be used for maintaining control of computer codes Testing has been performed at the add these requirements consistent with monitoring changes to used to support PRA quantification. discretion of the model owner. Note, industry best practices and NextEra the as operated, as however, the process does identify Energy fleet standards. maintained plant. The requirements for identifying code These procedures will be implemented list of changes as a versions and storing computer files. prior to using the PRA model for result of this scrutiny will quantifying the effect of a proposed be assessed as part of Move PRA software under the site individual STI revision. the Surveillance Software Quality Assurance program. Frequency Control Program.
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| MU-F1-01 No process for maintaining software PRA Software is used for calculation of DAEC is currently updating the The upgraded process configuration control was available for CDF/LERF and these are inputs to plant configuration and control procedures to will be used for review. decision making. add these requirements consistent with monitoring changes to industry best practices and NextEra the as operated, as Establish a process for acceptance of the Energy fleet standards. maintained plant. The PRA software and for updating as These procedures will be implemented list of changes as a changes are developed. prior to using the PRA model for result of this scrutiny will quantifying the effect of a proposed be assessed as part of individual STI revision. the Surveillance Frequency Control Program.
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| Attachment 2 to NG-11-0037 Page 27 of 35 Documentation of PRA Technical Adequacy TABLE 2-3 DISPOSITION OF PEER REVIEW SUGGESTION F&Os Importance to F&O Discussion Basis and Recommendation Disposition in PRA Update Application IE-A4a-01 Initiating events resulting from multiple Desirable to maintain maximum flexibility A Loss of River Water SSIE fault tree is Creating additional fault failures, common cause and routine in PRA applications and consistency with developed for this PRA update. Other trees for support system system alignments not included. This is industry practice. SSIEs in the DAEC PRA are initiators can be typically performed using fault tree appropriately quantified using Bayesian considered on a case-by-analysis approach. Develop initiating event fault trees for update of industry generic Prior case basis, depending support system initiators. distributions with DAEC operating upon the component(s) experience. being evaluated for a Surveillance Frequency The ASME Standard does not require evaluation.
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| that SSIE fault trees be developed nor, if developed, that they be linked into the accident sequence models. Given the difficulty in obtaining reasonable SSIE frequencies using SSIE fault trees and industry guidelines, pursuit of additional SSIE fault tree development is not pursued at this time.
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| Attachment 2 to NG-11-0037 Page 28 of 35 Documentation of PRA Technical Adequacy TABLE 2-3 DISPOSITION OF PEER REVIEW SUGGESTION F&Os Importance to F&O Discussion Basis and Recommendation Disposition in PRA Update Application AS-B5a-01 Many plant configurations are captured in Additional failure modes or dependencies Maintenance unavailabilities for the Creating additional fault the model. Additional configurations could be introduced. batteries and the chargers are included in trees for additional plant could be considered. Examples; RHR in the DC fault tree logic and discussed in configurations would be suppression cool pooling is not modeled Check the examples to determine the documentation. Configuration considered on a case-by-explicitly. This configuration can lead to whether an update to the model is probabilities are also included for the case basis, depending a RHR water hammer during a loss of needed to address plant alignments that chargers to model the potential that a upon the component(s) off-site power event. Also, the 125 VDC would add or change failure modes or swing charger is in operation. being evaluated for system configurations during on-line dependencies. Surveillance Frequency battery maintenance/testing is not Water hammer scenarios due to a LOCA Control Program.
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| described nor modeled. This signal initiator combined with SPC in maintenance activity alignment could operation at the time of the event and introduce additional failure modes or failure to put the RHR pumps in pull-to-battery charger dependencies. lock before load sequencing starts are not pursued at this time. Discussion with other industry BWR PRA personnel indicate that such scenarios have a tendency to be conservatively modeled.
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| Awaiting future industry clarification on these low frequency scenarios.
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| SC-B4-01 The MAAP runs reference MAAP 3B There have been some significant MAAP runs can be which has been replaced by MAAP 4.x. changes to the MAAP routines that may Conversion to MAAP4 is deferred for upgraded at the time of Upgrade past analyses to 4.0 series of impact the results of success criteria. future consideration. The PRA Standard the Surveillance MAAP. does not require a specific revision of the Frequency evaluation if Upgrade past analyses to 4.0 series of MAAP software or use of the MAAP deemed necessary.
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| MAAP. software.
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| Attachment 2 to NG-11-0037 Page 29 of 35 Documentation of PRA Technical Adequacy TABLE 2-3 DISPOSITION OF PEER REVIEW SUGGESTION F&Os Importance to F&O Discussion Basis and Recommendation Disposition in PRA Update Application SC-C1-01 The documentation is structured such It would aid reviewability and be of use to The Success Criteria Notebook has been Creating a cross that the MAAP analyses can be identified analysts to document the uses of the revised to refer to MAAP runs where reference between from the event tree. The uses of the MAAP runs used to document the appropriate for bases. MAAP runs and every MAAP runs, however, cannot be readily success criteria. This is not a place they are used identified. requirement but would be helpful. A cross-reference of MAAP run to every would not affect the use use in the PRA is deferred at this time. of the PRA Model for this Currently, the MAAP runs that are Such a cross-reference would be difficult application.
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| associated with specific success criteria to maintain.
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| for a specific event tree can readily be identified from the direction of the event tree. It would be helpful to have a cross-reference that identifies the uses of each MAAP run such that if a MAAP run is updated, the analyst can directly determine the SC and/or human action, etc. impacted by the update.
| |
| SY-B8-01 The Fault Tree Development Guideline For completeness the notebooks could DAEC is currently updating the The upgraded process (PTG-008) does not include the need to indicate that environmental/spatial issues configuration and control procedures to will be used for discuss (model if necessary) the impact were considered and there were/were not add these requirements consistent with monitoring changes to of environmental/spatial issues (not issues that needed to be included in the industry best practices and NextEra the as operated, as including fire/seismic/flooding issues). model. Energy fleet standards. maintained plant. The list These procedures will be implemented of changes that result Include a specific section in each prior to using the PRA model for from this scrutiny will be notebook associated with quantifying the effect of a proposed assessed as part of the environmental/spatial considerations. individual STI revision. Surveillance Frequency This section would include a statement Control Program.
| |
| that no such conditions exist or would describe the conditions.
| |
| | |
| Attachment 2 to NG-11-0037 Page 30 of 35 Documentation of PRA Technical Adequacy TABLE 2-3 DISPOSITION OF PEER REVIEW SUGGESTION F&Os Importance to F&O Discussion Basis and Recommendation Disposition in PRA Update Application LE-C8b-01 The SR expects the significant No objective evidence is provided that Documentation of review of results is Expanding the PRA sequences will be explicitly reviewed. significant sequences have been deferred for future consideration. Such Summary Notebook reviewed to determine whether continued an activity is judged at this time not an discussion to include system operation or operator actions efficient expenditure of resources for the detailed descriptions of would reduce LERF. base PRA. hundreds of sequences to identify where further Include the review of significant credit can be given for sequences expected by the SR. system operations or operator actions in order to reduce LERF would not affect the use of the PRA model for purposes of this application.
| |
| | |
| Attachment 2 to NG-11-0037 Page 31 of 35 Documentation of PRA Technical Adequacy TABLE 2-3 DISPOSITION OF PEER REVIEW SUGGESTION F&Os Importance to F&O Discussion Basis and Recommendation Disposition in PRA Update Application MU-D1-01 The PRA practitioner does not have a list The current process relies on tribal DAEC is currently updating the The updated procedures of support applications that are based on knowledge. Loss of key personnel could configuration and control procedures to will either contain a the PRA model. In addition, a change result in not updating all support add these requirements consistent with specific process for management plan to assure complete applications following a PRA update, or industry best practices and NextEra updating support and timely rollouts is not required by the not considering an application when Energy fleet standards. applications or require a current process. evaluating the importance of a PRA These procedures will be implemented change management change. Operating without a change prior to using the PRA model for plan be developed for management plan and associated action quantifying the effect of a proposed implementing an updated tracking items could lead to significant individual STI revision. or upgraded base PRA slippages in model rollout activities. model.
| |
| A process should be implemented to identify all PRA support applications and to identify if past applications are one time support applications or need to be revised following PRA updates.
| |
| An acceptable alternative would be to include in the PRA Maintenance and Update document a list of all applications that require updates following PRA updates. A change management plan template could be developed and applied to future updates.
| |
| | |
| Attachment 2 to NG-11-0037 Page 32 of 35 Documentation of PRA Technical Adequacy 2.2.4 Identification of Key Assumptions The overall Initiative 5b process is a risk-informed process with the PRA model results providing one of the inputs to the IDP to determine if an STI change is warranted. The methodology recognizes that a key area of uncertainty for this application is the standby failure rate utilized in the determination of the STI extension impact. Therefore, the methodology requires the performance of selected sensitivity studies on the standby failure rate of the component(s) of interest for the STI assessment.
| |
| The results of the standby failure rate sensitivity study plus the results of any additional sensitivity studies identified during the performance of the reviews as outlined in 2.2.1 and 2.2.3 above (including a review of identified sources of uncertainty that were developed for DAEC based on the EPRl 1016737 guidance
| |
| [Ref. 19]) for each STI change assessment will be documented and included in the results of the risk analysis that goes to the IDP.
| |
| 2.3 External Events Considerations The NEI 04-10 methodology allows for STI change evaluations to be performed in the absence of quantifiable PRA models for all external hazards. For those cases where the STI cannot be modeled in the plant PRA (or where a particular PRA model does not exist for a given hazard group), a qualitative or bounding analysis is performed to provide justification for the acceptability of the proposed test interval change.
| |
| External hazards were originally evaluated in the DAEC Individual Plant Examination of External Events (IPEEE) submittal in response to the NRC IPEEE Program (Generic Letter 88-20, Supplement 4) [Ref. 9]. The IPEEE Program was a one-time review of external hazard risk and was limited in its purpose to the identification of potential plant vulnerabilities and the understanding of associated severe accident risks. To provide consistency to the process, the classification of external hazards will remain the same as evaluated in the original IPEEE for implementation of the Surveillance Frequency Control Program.
| |
| In 1997 DAEC created a living External Events Model which includes the calculation of an overall CDF for external events. The current DAEC External Events PRA explicitly models internal fire and seismic initiated core damage accidents. These models are based on the original DAEC IPEEE (Individual Plant Examination of External Events) Submittal which showed fire and seismic events to be the most significant external hazards with respect to calculated CDF. The fire and seismic accident sequence logic was incorporated into the
| |
| | |
| Attachment 2 to NG-11-0037 Page 33 of 35 Documentation of PRA Technical Adequacy internal events PRA system fault tree logic. Starting in December of 2001, the External Events CDF is calculated at the same time as the Internal Events CDF.
| |
| In addition to internal fires and seismic events, the DAEC IPEEE analysis of high winds, floods, and other (HFO) external hazards was accomplished by reviewing the plant environs against regulatory requirements regarding these hazards. Since DAEC was designed (with construction started) prior to the issuance of the 1975 Standard Review Plan (SRP) criteria, Iowa Electric [now NextEra Energy Duane Arnold] performed a plant hazard and design information review for conformance with the SRP criteria. For seismic and fire events that were not screened out, additional analyses were performed to determine whether or not the hazard frequency was acceptably low. HFO events were screened out by compliance with the 1975 SRP criteria [Ref. 16]. As such, these hazards were determined in the DAEC IPEEE to be negligible contributors to overall plant risk.
| |
| The original Fire PRA was created using the EPRl FIVE Methodology [Ref. 11] and Fire PRA Implementation Guide (FPRAIG) [Ref. 13] screening approaches, using a combination of the EPRl Fire Events Database [Ref. 14] and plant specific data.
| |
| DAEC is developing a Fire PRA model that will be based on the NUREG/CR-6850 methodologies. A Fire Probabilistic Risk Assessment (FPRA) Peer Review was performed June/July 2010 at the site using the NEI 07-12 process, the ASME PRA Standard (ASME/ANS RA-Sa-2009) and Regulatory Guide 1.200, Rev. 2 under the auspices of the BWROG. The peer review final report was received in the fourth quarter of 2010. This new Fire PRA model for DAEC was built to support the NFPA 805 [Ref. 23] submittal scheduled for mid year 2011.
| |
| As stated earlier, the NEI 04-10 methodology allows for STI change evaluations to be performed in the absence of quantifiable PRA models for all external hazards.
| |
| Therefore, in performing the assessments for the other hazard groups, a qualitative or a bounding 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.
| |
| 2.4 Summary The DAEC PRA technical capability evaluations and the maintenance and update processes described above provide a robust basis for concluding that the DAEC PRA is suitable for use in risk-informed processes such as that proposed for the implementation of a Surveillance Frequency Control Program. Also, in addition to the standard set of sensitivity studies required per the NEI 04-10 methodology, open items for changes at the site and remaining gaps to specific requirements in the PRA standard will be reviewed to determine which, if any, would merit application-specific sensitivity studies in the presentation of the application results.
| |
| | |
| Attachment 2 to NG-11-0037 Page 34 of 35 Documentation of PRA Technical Adequacy 2.5 References
| |
| : 1) Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies, Industry Guidance Document, NEI 04-10, Revision 1, April 2007.
| |
| : 2) Regulatory Guide 1.200, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk Informed Activities, Revision 1, January 2007.
| |
| : 3) Boiling Water Reactors Owners' Group, BWROG PSA Peer Review Certification Implementation Guidelines, Revision 3, January 1997.
| |
| : 4) American Society of Mechanical Engineers, Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications, ASME RA-S-2002, New York, New York, April 2002.
| |
| : 5) U.S. Nuclear Regulatory Commission, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, Draft Regulatory Guide DG-1122, November 2002.
| |
| : 6) Duane Arnold Energy Center MSPl Basis Document, Rev. 9, December 2009.
| |
| : 7) American Society of Mechanical Engineers, Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications, (ASME RA-S-2002), Addenda RA-Sa-2003, December 2003.
| |
| : 8) American Society of Mechanical Engineers, Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications, (ASME RA-S-2002), Addenda RA-Sb-2005, December 2005.
| |
| : 9) American Society of Mechanical Engineers, Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications, (ASME RA-S-2002), Addenda RA-Sc-2007, August 2007.
| |
| : 10) U.S. Nuclear Regulatory Commission Memorandum to Michael T. Lesar from Farouk Eltawila, "Notice of Clarification to Revision 1 of Regulatory Guide 1.200,"
| |
| for publication as a Federal Register Notice, July 27, 2007.
| |
| : 11) NRC Generic Letter 88-20, "lndividual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities - 10 CFR 50.54(f), Supplement 4,"
| |
| June 28, 1991.
| |
| : 12) IES Utilities, Inc., Duane Arnold Energy Center, Individual Plant Examination for External Events, Main Report, November 1995.
| |
| | |
| Attachment 2 to NG-11-0037 Page 35 of 35 Documentation of PRA Technical Adequacy
| |
| : 13) Professional Loss Control, Inc., Fire-Induced Vulnerability Evaluation (FIVE)
| |
| Methodology Plant Screening Guide, EPRl TR-100370, Electric Power Research Institute, Final Report, April 1992.
| |
| : 14) NTS Engineering, ET. al., A Method for Assessment of Nuclear Power Plant Seismic Margin, EPRl NP-6041, Electric Power Research Institute, Final Report, August 1991.
| |
| : 15) W.J. Parkinson, et. al., Fire PRA Implementation Guide, EPRl TR-105928, Electric Power Research Institute, December 1995.
| |
| : 16) NSAC/179L, Electric Power Research Institute, Fire Events Database for U.S.
| |
| Nuclear Power Plants, Rev. 1, January, 1993.
| |
| : 17) EPRIJNRC-RES, Fire PRA Methodology for Nuclear Power Facilities, EPRl 101 1989, NUREG/CR-6850, Final Report, September 2005.
| |
| : 18) Letter from Brenda L. Mozafari (USNRC) to Elliot Protsch (IES Utilities Inc.),
| |
| Review of Individual Plant Examination of External Events Submittal, Duane Arnold Energy Center (TAC No. M83618), March 10, 2000.
| |
| : 19) Treatment of Parameter and Model Uncertainty for Probabilistic Risk Assessments, EPRI, Palo Alto, CA: December 2008 (Final). 1016737.
| |
| : 20) Self Assessment of the DAEC PRA Against the ASME PRA Standard Requirements, November 2007.
| |
| : 21) 2007 Peer Review of the Duane Arnold Energy Canter PRA using the NEI 05-04 Process, December 2007.
| |
| : 22) DAEC PSA Peer Review Certification Report, BWROG/PSA-9701, March 1997.
| |
| : 23) NFPA 805, Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants (2001 Edition)
| |
| | |
| Attachment 3 To NG-11-0037 PROPOSED TECHNICAL SPECIFICATION CHANGES (MARK-UPS) 133 Pages to Follow
| |
| | |
| INSERT 1 In accordance with the Surveillance Frequency Control Program INSERT 2 5.5.14 Surveillance Frequency Control Program This program provides controls for Surveillance Frequencies. The program shall ensure that Surveillance Requirements specified in the Technical Specifications are performed at intervals sufficient to assure the associated Limiting Conditions for Operation are met.
| |
| : a. The Surveillance Frequency Control Program shall contain a list of Frequencies of those Surveillance Requirements for which the Frequency is controlled by the program.
| |
| : b. Changes to the Frequencies listed in the Surveillance Frequency Control Program shall be made in accordance with NEI 04-10, "Risk-Informed Method for Control of Surveillance Frequencies,"
| |
| Revision 1.
| |
| : c. The provisions of Surveillance Requirements 3.0.2 and 3.0.3 are applicable to the Frequencies established in the Surveillance Frequency Control Program.
| |
| | |
| Definitions 1.1 1.1 Definitions (continued)
| |
| SHUTDOWN MARGIN SDM shall be the amount of reactivity by which the (SDM) reactor is subcritical or would be subcritical assuming that:
| |
| : a. The reactor is xenon free;
| |
| : b. The moderator temperature is 68°F (20°C); and
| |
| : c. All control rods are fully inserted except for the single control rod of highest reactivity worth, which is assumed to be fully withdrawn with the core in its most reactive state during the operating cycle.
| |
| With control rods not capable of being fully inserted, the reactivity worth of these control rods must be accounted for in the determination of SDM.
| |
| STAGGERED TEST BASIS A STAGGERED TEST BASIS shall consist of the testing of one of the systems, subsystems, channels, or other designated components during the interval specified by the Surveillance Frequency, so that all systems, subsystems, channels, or other designated components are tested during n Surveillance Frequency intervals, where n is the total number of systems, subsystems, channels, or other designated components in the associated function.
| |
| (continued)
| |
| TSCR-120 DAEC 1.1-6 Amendment No. 223
| |
| | |
| Control Rod OPERABILITY 3.1.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.3.1 Determine the position of each control rod. 24 hours SR 3.1.3.2 ---------------------------NOTE----------------------------
| |
| Not required to be performed until 31 days after the control rod is withdrawn and THERMAL INSERT 1 POWER is greater than 20% RTP.
| |
| Insert each withdrawn control rod at least one 31 days notch.
| |
| SR 3.1.3.3 Verify each control rod scram time from fully In accordance withdrawn to notch position 04 is with SR 3.1.4.1 7 seconds. and SR 3.1.4.2 SR 3.1.3.4 Verify each withdrawn control rod does not Each time the go to the withdrawn overtravel position. control rod is withdrawn to full out position AND Prior to declaring control rod OPERABLE after work on control rod or CRD System that could affect coupling TSCR-120 DAEC 3.1-10 Amendment 271
| |
| | |
| Control Rod Scram Accumulators 3.1.5 ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME C. One or more control rod C.1 Verify all control rods Immediately upon scram accumulators associated with discovery of charging inoperable with reactor inoperable water header steam dome pressure accumulators are pressure
| |
| < 900 psig. fully inserted. < 940 psig AND C.2 Declare the 1 hour associated control rod inoperable.
| |
| D. Required Action and D.1 ------------NOTE------------
| |
| associated Not applicable if all Completion Time of inoperable control Required Action B.1 rod scram or C.1 not met. accumulators are associated with fully inserted control rods.
| |
| Place the reactor Immediately mode switch in the Shutdown position.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.5.1 Verify each control rod scram accumulator 7 days INSERT 1 pressure is 940 psig.
| |
| TSCR-120 DAEC 3.1-17 Amendment 223
| |
| | |
| Rod Pattern Control 3.1.6 ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME B. Nine or more B.1 -------------NOTE-------------
| |
| OPERABLE control rods Rod Worth Minimizer not in compliance with (RWM) may be bypassed BPWS. as allowed by LCO 3.3.2.1.
| |
| Suspend withdrawal of Immediately control rods.
| |
| AND B.2 Place the reactor 1 hour mode switch in the Shutdown position.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY INSERT 1 SR 3.1.6.1 Verify all OPERABLE control rods comply 24 hours with BPWS.
| |
| TSCR-120 DAEC 3.1-19 Amendment 223
| |
| | |
| SLC System 3.1.7 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.7.1 Verify available volume of sodium pentaborate 24 hours solution is within the limits of Figure 3.1.7-1.
| |
| SR 3.1.7.2 Verify temperature of sodium pentaborate 24 hours solution is within the limits of Figure 3.1.7-2.
| |
| SR 3.1.7.3 Verify temperature of pump suction piping is 24 hours within the limits of Figure 3.1.7-2. INSERT 1 SR 3.1.7.4 Verify continuity of explosive charge. 31 days SR 3.1.7.5 Verify the concentration of boron in 31 days solution is within the limits of Figure 3.1.7-1. AND Once within 24 hours after water or boron is added to solution AND Once within 24 hours after solution temperature is restored within the limits of Figure 3.1.7-2 (continued)
| |
| TSCR-120 DAEC 3.1-21 Amendment 223
| |
| | |
| SLC System 3.1.7 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.1.7.6 Verify each pump develops a flow rate In accordance 26.2 gpm at a discharge pressure 1150 with the psig. Inservice Testing Program SR 3.1.7.7 Verify flow through one SLC subsystem from 24 months on a pump into reactor pressure vessel. STAGGERED TEST BASIS INSERT 1 SR 3.1.7.8 Verify all heat traced piping between storage 24 months tank and pump suction is unblocked.
| |
| AND Once within 24 hours after solution temperature is restored within the limits of Figure 3.1.7-2 TSCR-120 DAEC 3.1-22 Amendment 223
| |
| | |
| SDV Vent and Drain Valves 3.1.8 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.8.1 ------------------------------NOTE---------------------------
| |
| Not required to be met on vent and drain valves closed during the performance of SR 3.1.8.2.
| |
| Verify each SDV vent and drain valve is 31 days open. INSERT 1 SR 3.1.8.2 Cycle each SDV vent and drain valve to the fully In accordance closed and fully open position. with the Inservice Testing Program SR 3.1.8.3 Verify each SDV vent and drain valve: 24 months
| |
| : a. Closes in 30 seconds after receipt of an actual or simulated scram signal; and
| |
| : b. Opens when the actual or simulated scram signal is reset.
| |
| TSCR-102 DAEC 3.1-26 Amendment 223
| |
| | |
| APLHGR 3.2.1 3.2 POWER DISTRIBUTION LIMITS 3.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)
| |
| LCO 3.2.1 All APLHGRs shall be less than or equal to the limits specified in the COLR.
| |
| APPLICABILITY: THERMAL POWER 21.7% RTP.
| |
| ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Any APLHGR not within A.1 Restore APLHGR(s) to 2 hours limits. within limits.
| |
| B. Required Action and B.1 Reduce THERMAL 4 hours associated Completion POWER to < 21.7%
| |
| Time not met. RTP.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.2.1.1 Verify all APLHGRs are less than or equal to Once within the limits specified in the COLR. 12 hours after 21.7% RTP AND 24 hours thereafter INSERT 1 TSCR-120 DAEC 3.2-1 Amendment 243
| |
| | |
| MCPR 3.2.2 3.2 POWER DISTRIBUTION LIMITS 3.2.2 MINIMUM CRITICAL POWER RATIO (MCPR)
| |
| LCO 3.2.2 All MCPRs shall be greater than or equal to the MCPR operating limits specified in the COLR.
| |
| APPLICABILITY: THERMAL POWER 21.7% RTP.
| |
| ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Any MCPR not within A.1 Restore MCPR(s) to 2 hours limits. within limits.
| |
| B. Required Action and B.1 Reduce THERMAL 4 hours associated Completion POWER to < 21.7%
| |
| Time not met. RTP.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.2.2.1 Verify all MCPRs are greater than or equal to Once within the limits specified in the COLR. 12 hours after 21.7% RTP AND INSERT 1 24 hours thereafter (continued)
| |
| TSCR-120 DAEC 3.2-2 Amendment 243
| |
| | |
| RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS
| |
| -----------------------------------------------------NOTES--------------------------------------------------
| |
| : 1. Refer to Table 3.3.1.1-1 to determine which SRs apply for each RPS Function.
| |
| : 2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains RPS trip capability.
| |
| SURVEILLANCE FREQUENCY INSERT 1 SR 3.3.1.1.1 Perform CHANNEL CHECK. 12 hours SR 3.3.1.1.2 ---------------------------NOTE----------------------------
| |
| Not required to be performed until 12 hours after THERMAL POWER 21.7%
| |
| RTP.
| |
| INSERT 1 Verify the absolute difference between 24 hours the Average Power Range Monitor (APRM) channels and the calculated power is 2% RTP plus any gain adjustment required by LCO 3.4.1, Recirculation Loops Operating, while operating at 21.7% RTP.
| |
| INSERT 1 SR 3.3.1.1.3 Perform a functional test of each 7 days automatic scram contactor.
| |
| SR 3.3.1.1.4 ----------------------------NOTE---------------------------
| |
| Not required to be performed when entering MODE 2 from MODE 1 until 12 hours after entering MODE 2.
| |
| INSERT 1 Perform CHANNEL FUNCTIONAL TEST. 7 days (continued)
| |
| TSCR-120 DAEC 3.3-3 Amendment 243
| |
| | |
| RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY INSERT 1 SR 3.3.1.1.5 Perform CHANNEL FUNCTIONAL TEST. 7 days SR 3.3.1.1.6 Verify the Source Range Monitor (SRM) and Prior to Intermediate Range Monitor (IRM) channels withdrawing overlap. SRMs from the fully inserted position SR 3.3.1.1.7 --------------------------NOTE-------------------------
| |
| Only required to be met during entry into MODE 2 from MODE 1.
| |
| INSERT 1 Verify the IRM and APRM channels overlap. 7 days INSERT 1 SR 3.3.1.1.8 Calibrate the local power range monitors. 1000 MWD/T average core exposure SR 3.3.1.1.9 Perform CHANNEL FUNCTIONAL TEST. 92 days 9 INSERT 1 SR 3.3.1.1.10 Calibrate the trip units. 92 days 10 INSERT 1 SR 3.3.1.1.11 Perform CHANNEL CALIBRATION. 92 days (continued)
| |
| TSCR-120 DAEC 3.3-4 Amendment 223
| |
| | |
| RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY 11 SR 3.3.1.1.12 ------------------------NOTES---------------------------
| |
| : 1. Neutron detectors are excluded.
| |
| Functions 1 and
| |
| : 2. For Function 2.a, not required to be performed when entering MODE 2 from MODE 1 until 12 hours after entering MODE 2.
| |
| INSERT 1 Perform CHANNEL CALIBRATION. 184 days SR 3.3.1.1.13 Perform CHANNEL FUNCTIONAL TEST. 24 months SR 3.3.1.1.14 -------------------------NOTES--------------------------
| |
| : 1. Neutron detectors are excluded.
| |
| : 2. For Function 1, not required to be performed when entering MODE 2 from MODE 1 until 12 hours after entering MODE 2.
| |
| Perform CHANNEL CALIBRATION. 24 months 12 INSERT 1 SR 3.3.1.1.15 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months 13 INSERT 1 SR 3.3.1.1.16 Verify Turbine Stop Valve-Closure and 24 months Turbine Control Valve Fast Closure, Trip Oil Pressure - Low Functions are not bypassed when THERMAL POWER is 26% RTP.
| |
| (continued)
| |
| TSCR-120 DAEC 3.3-5 Amendment 243
| |
| | |
| RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY 14 INSERT 1 SR 3.3.1.1.17 Adjust the channel to conform to a calibrated 24 months flow signal.
| |
| 15 INSERT 1 SR 3.3.1.1.18 Verify the RPS RESPONSE TIME is within 24 months on a limits. STAGGERED TEST BASIS 16 SR 3.3.1.1.19 Verify the RPS logic system response time is 24 months on a INSERT 1 within limits. STAGGERED TEST BASIS TSCR-120 DAEC 3.3-6 Amendment 223
| |
| | |
| RPS Instrumentation 3.3.1.1 Table 3.3.1.1-1 (page 1 of 3)
| |
| Reactor Protection System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION D.1 REQUIREMENTS VALUE
| |
| : 1. Intermediate Range Monitors
| |
| : a. Neutron 2 2 G SR 3.3.1.1.1 < 125/125 divisions of Flux - High SR 3.3.1.1.4 full scale SR 3.3.1.1.6 SR 3.3.1.1.7 SR 3.3.1.1.14 11 SR 3.3.1.1.15 12 SR 3.3.1.1.19 16 (a) 2 H SR 3.3.1.1.1 < 125/125 divisions of 5
| |
| SR 3.3.1.1.5 full scale SR 3.3.1.1.14 11 SR 3.3.1.1.15 12 SR 3.3.1.1.19 16
| |
| : b. Inop 2 2 G SR 3.3.1.1.4 NA SR 3.3.1.1.15 12 SR 3.3.1.1.19 16 (a) 2 H SR 3.3.1.1.5 NA 5
| |
| SR 3.3.1.1.15 12 SR 3.3.1.1.19 16
| |
| : 2. Average Power Range Monitors
| |
| : a. Neutron 2 2 G SR 3.3.1.1.1 < 16.6% RTP Flux - SR 3.3.1.1.4 Upscale, SR 3.3.1.1.7 Startup SR 3.3.1.1.8 SR 3.3.1.1.12 11 SR 3.3.1.1.15 12 SR 3.3.1.1.19 16
| |
| : b. Flow Biased - 1 2 F SR 3.3.1.1.1 (b) (c)
| |
| < (0.55W + 67.7)
| |
| High SR 3.3.1.1.2 SR 3.3.1.1.3 SR 3.3.1.1.8 5 SR 3.3.1.1.9 11 SR 3.3.1.1.12 SR 3.3.1.1.15 12 SR 3.3.1.1.17 14 SR 3.3.1.1.19 16 (Continued)
| |
| (a) With any control rod withdrawn from a core cell containing one or more fuel assemblies.
| |
| (b) When reset for single loop operation per LCO 3.4.1, "Recirculation Loops Operating," the following Allowable Value applies:
| |
| (c)
| |
| < (0.55W + 61.4)
| |
| The trip setpoints may be reset by adjusting APRM gain or by recalibrating the APRMs.
| |
| (c) W is equal to the percentage of the drive flow, where 100% drive flow is that required to achieve 100% core flow at 100% RTP.
| |
| TSCR-120 DAEC 3.3-7 Amendment 243
| |
| | |
| RPS Instrumentation 3.3.1.1 Table 3.3.1.1-1 (page 2 of 3)
| |
| Reactor Protection System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION D.1 REQUIREMENTS VALUE
| |
| : 2. Average Power Range Monitors (continued)
| |
| : c. High Value Clamp 1 2 F SR 3.3.1.1.2 < 121.6% RTP SR 3.3.1.1.3 SR 3.3.1.1.8 5 SR 3.3.1.1.9 SR 3.3.1.1.12 11 SR 3.3.1.1.15 12 SR 3.3.1.1.19 16
| |
| : d. Inop 1,2 2 G SR 3.3.1.1.3 NA SR 3.3.1.1.9 5
| |
| SR 3.3.1.1.15 12 SR 3.3.1.1.19 16
| |
| : 3. Reactor Vessel Steam 1,2 2 G SR 3.3.1.1.3 5 < 1069.2 psig Dome Pressure - High SR 3.3.1.1.9 SR 3.3.1.1.11 10 SR 3.3.1.1.15 12 SR 3.3.1.1.18 15 SR 3.3.1.1.19 16
| |
| : 4. Reactor Vessel Water 1,2 2 G SR 3.3.1.1.1 > 165.6 inches Level - Low SR 3.3.1.1.3 5 SR 3.3.1.1.9 SR 3.3.1.1.14 11 SR 3.3.1.1.15 12 SR 3.3.1.1.18 15 SR 3.3.1.1.19 16
| |
| : 5. Main Steam Isolation 1 4 F SR 3.3.1.1.3 < 10% closed Valve - Closure SR 3.3.1.1.9 5
| |
| SR 3.3.1.1.14 11 SR 3.3.1.1.15 12 SR 3.3.1.1.19 16
| |
| : 6. Drywell Pressure - High 1,2 2 G SR 3.3.1.1.3 < 2.2 psig SR 3.3.1.1.9 5 SR 3.3.1.1.14 11 SR 3.3.1.1.15 12 SR 3.3.1.1.19 16 (continued)
| |
| TSCR-120 DAEC 3.3-8 Amendment 223
| |
| | |
| RPS Instrumentation 3.3.1.1 Table 3.3.1.1-1 (page 3 of 3)
| |
| Reactor Protection System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION D.1 REQUIREMENTS VALUE
| |
| : 7. Scram Discharge Volume Water Level - High
| |
| : a. Resistance 1,2 2 G SR 3.3.1.1.3 5 < 769 ft -
| |
| Temperature SR 3.3.1.1.10 3.0 inches Detector SR 3.3.1.1.13 9 SR 3.3.1.1.14 11 SR 3.3.1.1.15 12 SR 3.3.1.1.19 16 (a) 2 H SR 3.3.1.1.3 < 769 ft -
| |
| 5 5 SR 3.3.1.1.10 3.0 inches SR 3.3.1.1.13 9 SR 3.3.1.1.14 11 SR 3.3.1.1.15 SR 3.3.1.1.19 12 16
| |
| : b. Float Switch 1,2 2 G SR 3.3.1.1.3 < 769 ft -
| |
| SR 3.3.1.1.9 5 2.8 inches SR 3.3.1.1.14 11 SR 3.3.1.1.15 12 SR 3.3.1.1.19 16 (a) 2 H SR 3.3.1.1.3 < 769 ft -
| |
| 5 5 SR 3.3.1.1.9 2.8 inches SR 3.3.1.1.14 11 SR 3.3.1.1.15 12 SR 3.3.1.1.19 16
| |
| : 8. Turbine Stop Valve - > 26% 4 E SR 3.3.1.1.3 5 < 10% closed Closure RTP SR 3.3.1.1.9 11 SR 3.3.1.1.14 SR 3.3.1.1.15 12 SR 3.3.1.1.16 13 SR 3.3.1.1.19 16
| |
| : 9. Turbine Control Valve > 26% 2 E SR 3.3.1.1.3 5 > 465 psig Fast Closure, Trip Oil RTP SR 3.3.1.1.9 11 Pressure - Low SR 3.3.1.1.14 SR 3.3.1.1.15 12 SR 3.3.1.1.16 13 SR 3.3.1.1.19 16
| |
| : 10. Reactor Mode Switch - 1,2 1 G SR 3.3.1.1.13 5 NA Shutdown Position SR 3.3.1.1.15 12 (a) 1 H SR 3.3.1.1.13 NA 5 5 SR 3.3.1.1.15 12
| |
| : 11. Manual Scram 1,2 1 G SR 3.3.1.1.9 NA SR 3.3.1.1.15 5 (a) 1 H SR 3.3.1.1.9 12 NA 5
| |
| SR 3.3.1.1.15 5 12 (a) With any control rod withdrawn from a core cell containing one or more fuel assemblies.
| |
| TSCR-120 DAEC 3.3-9 Amendment 243
| |
| | |
| SRM Instrumentation 3.3.1.2 SURVEILLANCE REQUIREMENTS
| |
| ----------------------------------------------------NOTE--------------------------------------------------------
| |
| Refer to Table 3.3.1.2-1 to determine which SRs apply for each applicable MODE or other specified conditions.
| |
| SURVEILLANCE FREQUENCY SR 3.3.1.2.1 Perform CHANNEL CHECK. 12 hours SR 3.3.1.2.2 --------------------------NOTES--------------------------
| |
| : 1. Only required to be met during CORE ALTERATIONS.
| |
| INSERT 1
| |
| : 2. One SRM may be used to satisfy more than one of the following.
| |
| Verify an OPERABLE SRM detector is 12 hours located in :
| |
| : a. The fueled region;
| |
| : b. The core quadrant where CORE ALTERATIONS are being performed, when the associated SRM is included in the fueled region; and
| |
| : c. A core quadrant adjacent to where CORE ALTERATIONS are being performed, when the associated SRM is included in the fueled region.
| |
| SR 3.3.1.2.3 Perform CHANNEL CHECK. 24 hours (continued)
| |
| TSCR-120 DAEC 3.3-12 Amendment 223
| |
| | |
| SRM Instrumentation 3.3.1.2 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY 3
| |
| SR 3.3.1.2.4 ------------------------NOTE------------------------------
| |
| Not required to be met with less than or equal to four fuel assemblies adjacent to the SRM and no other fuel assemblies in the associated core quadrant.
| |
| Verify count rate is 3.0 cps. 12 hours during CORE ALTERATIONS AND 24 hours 4
| |
| SR 3.3.1.2.5 Perform CHANNEL FUNCTIONAL TEST. 7 days 5
| |
| SR 3.3.1.2.6 ------------------------NOTE------------------------------
| |
| Not required to be performed until INSERT 1 12 hours after IRMs on Range 2 or below.
| |
| Perform CHANNEL FUNCTIONAL TEST. 31 days 6
| |
| SR 3.3.1.2.7 -----------------------NOTES-----------------------------
| |
| : 1. Neutron detectors are excluded.
| |
| : 2. Not required to be performed until 12 hours after IRMs on Range 2 or below.
| |
| Perform CHANNEL CALIBRATION. 24 months TSCR-120 DAEC 3.3-13 Amendment 223
| |
| | |
| SRM Instrumentation 3.3.1.2 Table 3.3.1.2-1 (page 1 of 1)
| |
| Source Range Monitor Instrumentation APPLICABLE MODES OR OTHER REQUIRED SURVEILLANCE FUNCTION SPECIFIED CONDITIONS CHANNELS REQUIREMENTS
| |
| : 1. Source Range Monitor (a) 3 SR 3.3.1.2.1 2 3 SR 3.3.1.2.4 SR 3.3.1.2.6 5 SR 3.3.1.2.7 6 3,4 2 SR 3.3.1.2.3 1 SR 3.3.1.2.4 3 SR 3.3.1.2.6 5 SR 3.3.1.2.7 6
| |
| 5 (b) (c) SR 3.3.1.2.1 2
| |
| SR 3.3.1.2.2 3 SR 3.3.1.2.4 SR 3.3.1.2.5 4 SR 3.3.1.2.7 6 (a) With IRMs on Range 2 or below.
| |
| (b) Only one SRM channel is required to be OPERABLE during spiral offload or reload when the fueled region includes only that SRM detector.
| |
| (c) Special movable detectors may be used in place of SRMs if connected to normal SRM circuits.
| |
| TSCR-120 DAEC 3.3-14 Amendment 223
| |
| | |
| Control Rod Block Instrumentation 3.3.2.1 ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME E. One or more Reactor E.1 Suspend control rod Immediately Mode Switch - withdrawal.
| |
| Shutdown Position channels inoperable. AND E.2 Initiate action to fully Immediately insert all insertable control rods in core cells containing one or more fuel assemblies.
| |
| SURVEILLANCE REQUIREMENTS
| |
| --------------------------------------------------------NOTES--------------------------------------------------
| |
| : 1. Refer to Table 3.3.2.1-1 to determine which SRs apply for each Control Rod Block Function.
| |
| : 2. When an RBM channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains control rod block capability.
| |
| SURVEILLANCE FREQUENCY INSERT 1 SR 3.3.2.1.1 Perform CHANNEL FUNCTIONAL TEST. 92 days (continued)
| |
| TSCR-120 DAEC 3.3-17 Amendment 223
| |
| | |
| Control Rod Block Instrumentation 3.3.2.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.3.2.1.2 ---------------------------NOTE----------------------------
| |
| Not required to be performed until 1 hour after any control rod is withdrawn at 10% RTP in MODE 2.
| |
| Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.2.1.3 ---------------------------NOTE---------------------------
| |
| Not required to be performed until 1 hour after THERMAL POWER is 10 % RTP in INSERT 1 MODE 1.
| |
| Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.2.1.4 ---------------------------NOTE---------------------------
| |
| Neutron detectors are excluded.
| |
| Verify the RBM: 184 days
| |
| : a. Low Power Range - Upscale Function is not bypassed when THERMAL POWER is 29% and < 64% RTP.
| |
| : b. Intermediate Power Range - Upscale Function is not bypassed when THERMAL POWER is 64% and < 84% RTP.
| |
| : c. High Power Range - Upscale Function is not bypassed when THERMAL POWER is 84% RTP.
| |
| (continued)
| |
| TSCR-120 DAEC 3.3-18 Amendment 223
| |
| | |
| Control Rod Block Instrumentation 3.3.2.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.3.2.1.5 ---------------------------NOTE-------------------------
| |
| Neutron detectors are excluded.
| |
| Perform CHANNEL CALIBRATION. 184 days SR 3.3.2.1.6 ---------------------------NOTE-------------------------
| |
| INSERT 1 Not required to be performed until 1 hour after reactor mode switch is in the shutdown position.
| |
| Perform CHANNEL FUNCTIONAL TEST. 24 months SR 3.3.2.1.7 Verify control rod sequences input to the RWM Prior to are in conformance with BPWS. declaring RWM OPERABLE following loading of sequence into RWM TSCR-120 DAEC 3.3-19 Amendment 223
| |
| | |
| PAM Instrumentation 3.3.3.1 SURVEILLANCE REQUIREMENTS
| |
| --------------------------------------------------NOTE---------------------------------------------------------
| |
| These SRs apply to each Function in Table 3.3.3.1-1.
| |
| SURVEILLANCE FREQUENCY SR 3.3.3.1.1 Perform CHANNEL CHECK. 31 days INSERT 1 SR 3.3.3.1.2 Perform CHANNEL CALIBRATION. 24 months TSCR-120 DAEC 3.3-23 Amendment 223
| |
| | |
| Remote Shutdown System 3.3.3.2 3.3 INSTRUMENTATION 3.3.3.2 Remote Shutdown System LCO 3.3.3.2 The Remote Shutdown System Functions shall be OPERABLE.
| |
| APPLICABILITY: MODES 1 and 2.
| |
| ACTIONS
| |
| --------------------------------------------------------NOTE---------------------------------------------------
| |
| Separate Condition entry is allowed for each Function.
| |
| CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required A.1 Restore required 30 days Functions inoperable. Function to OPERABLE status.
| |
| B. Required Action and B.1 Be in MODE 3. 12 hours associated Completion Time not met.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY INSERT 1 SR 3.3.3.2.1 Verify each required control circuit and 24 months transfer switch is capable of performing the intended function.
| |
| (continued)
| |
| TSCR-120 DAEC 3.3-25 Amendment 255
| |
| | |
| Remote Shutdown System 3.3.3.2 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY INSERT 1 SR 3.3.3.2.2 Perform CHANNEL CALIBRATION for each 24 months required instrumentation channel.
| |
| TSCR-120 DAEC 3.3-26 Amendment 223
| |
| | |
| EOC-RPT Instrumentation 3.3.4.1 ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME B. One or more Functions B.1 Restore EOC-RPT trip 2 hours with EOC-RPT trip capability.
| |
| capability not maintained. OR AND B.2 Apply the MCPR limit 2 hours for inoperable MCPR limit for EOC-RPT as inoperable EOC-RPT specified in the COLR.
| |
| not made applicable.
| |
| C. Required Action and C.1 Remove the 4 hours associated Completion associated Time not met. recircluation pump from service.
| |
| OR C.2 Reduce THERMAL 4 hours POWER to < 26%
| |
| RTP.
| |
| SURVEILLANCE REQUIREMENTS
| |
| -------------------------------------------------------NOTE-----------------------------------------------------
| |
| When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains EOC-RPT trip capability.
| |
| SURVEILLANCE FREQUENCY SR 3.3.4.1.1 Perform CHANNEL FUNCTIONAL TEST. 92 days INSERT 1 (continued)
| |
| TSCR-120 DAEC 3.3-28 Amendment 243
| |
| | |
| EOC-RPT Instrumentation 3.3.4.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.3.4.1.2 Perform CHANNEL CALIBRATION. The 24 months Allowable Values shall be:
| |
| TSV - Closure: 10% closed; and TCV Fast Closure, Trip Oil Pressure - Low:
| |
| INSERT 1 465 psig.
| |
| SR 3.3.4.1.3 Perform LOGIC SYSTEM FUNCTIONAL 24 months TEST including breaker actuation.
| |
| SR 3.3.4.1.4 Verify TSV - Closure and TCV Fast Closure, 24 months Trip Oil Pressure - Low Functions are not bypassed when THERMAL POWER is 26 %
| |
| RTP.
| |
| SR 3.3.4.1.5 Verify the EOC-RPT SYSTEM RESPONSE 24 months on a TIME is within limits. STAGGERED TEST BASIS TSCR-120 DAEC 3.3-29 Amendment 243
| |
| | |
| ATWS-RPT Instrumentation 3.3.4.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.4.2.1 Perform CHANNEL CHECK on the Reactor 12 hours Vessel Water Level - Low Low Function.
| |
| SR 3.3.4.2.2 Perform CHANNEL FUNCTIONAL TEST. 12 months INSERT 1 SR 3.3.4.2.3 Perform CHANNEL CALIBRATION. The 12 months Allowable Values shall be:
| |
| : a. Reactor Vessel Water Level - Low Low 112.65 inches; and
| |
| : b. Reactor Steam Dome Pressure - High:
| |
| 1154.2 psig.
| |
| SR 3.3.4.2.4 Perform LOGIC SYSTEM FUNCTIONAL 24 months TEST including breaker actuation.
| |
| TSCR-120 DAEC 3.3-31 Amendment 223
| |
| | |
| ECCS Instrumentation 3.3.5.1 SURVEILLANCE REQUIREMENTS
| |
| ------------------------------------------------------NOTES----------------------------------------------------
| |
| : 1. Refer to Table 3.3.5.1-1 to determine which SRs apply for each ECCS Function.
| |
| : 2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed as follows: (a) for up to 6 hours for Functions 1.d, 2.f, 3.c, 3.d, 3.e, and 3.f; and (b) for up to 6 hours for Functions other than 1.d, 2.f, 3.c, 3.d, 3.e, and 3.f provided the associated Function (or the redundant Function for Functions 4 and 5) maintains ECCS initiation or loop selection capability.
| |
| SURVEILLANCE FREQUENCY SR 3.3.5.1.1 Perform CHANNEL CHECK. 24 hours SR 3.3.5.1.2 Perform CHANNEL FUNCTIONAL 31 days TEST.
| |
| INSERT 1 SR 3.3.5.1.3 Perform CHANNEL FUNCTIONAL 92 days TEST.
| |
| 3 SR 3.3.5.1.4 Perform CHANNEL CALIBRATION. 92 days SR 3.3.5.1.5 Perform CHANNEL FUNCTIONAL 12 months TEST.
| |
| SR 3.3.5.1.6 Perform CHANNEL CALIBRATION. 12 months (continued)
| |
| TSCR-120 DAEC 3.3-39 Amendment 223
| |
| | |
| ECCS Instrumentation 3.3.5.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.3.5.1.7 Perform CHANNEL CALIBRATION. 18 months SR 3.3.5.1.8 Perform CHANNEL CALIBRATION. 24 months 4
| |
| SR 3.3.5.1.9 Perform LOGIC SYSTEM FUNCTIONAL 24 months INSERT 1 TEST.
| |
| TSCR-120 DAEC 3.3-40 Amendment 223
| |
| | |
| ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 1 of 5)
| |
| Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS MODES REQUIRED REFERENCED OR OTHER CHANNELS FROM SPECIFIED PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE
| |
| : 1. Core Spray System
| |
| : a. Reactor Vessel Water 1,2,3, (b) B SR 3.3.5.1.1 > 38.3 inches 4 2 Level - Low Low Low (a) (a) SR 3.3.5.1.3 4 ,5 SR 3.3.5.1.8 3
| |
| SR 3.3.5.1.9 4
| |
| : b. Drywell Pressure - 1,2,3 (b) B SR 3.3.5.1.3 2 < 2.19 psig 4
| |
| High SR 3.3.5.1.8 3 SR 3.3.5.1.9 4
| |
| : c. Reactor Steam Dome 1,2,3 4 C SR 3.3.5.1.3 2 > 363.3 psig Pressure - Low SR 3.3.5.1.8 3 and < 485.1 psig (Injection Permissive) SR 3.3.5.1.9 4 > 363.3 psig (a) (a) 4 ,5 4 B SR 3.3.5.1.3 2 SR 3.3.5.1.8 and < 485.1 psig SR 3.3.5.1.9 3
| |
| 4
| |
| : d. Core Spray Pump 1,2,3, 1 per E SR 3.3.5.1.3 2 > 256.6 gpm Discharge Flow - Low (a) (a) pump SR 3.3.5.1.8 and (Bypass) 4 ,5 SR 3.3.5.1.9 3 < 2382.1 gpm 4
| |
| : e. Core Spray Pump Start 1,2,3, 1 per C SR 3.3.5.1.8 3 > 2.6 seconds Time Delay Relay (a) (a) pump SR 3.3.5.1.9 4 and < 6.8 seconds 4 ,5
| |
| : f. 4.16 kV Emergency Bus 1,2,3, 1 per F SR 3.3.5.1.5 2 < 3500 V Sequential Loading (a) (a) pump SR 3.3.5.1.6 3 Relay 4 ,5 SR 3.3.5.1.9 4
| |
| : 2. Low Pressure Coolant Injection (LPCI) System
| |
| : a. Reactor Vessel Water 1,2,3, 4 B SR 3.3.5.1.1 > 38.3 inches Level- Low Low Low (a) (a) SR 3.3.5.1.3 2 4 ,5 SR 3.3.5.1.8 3 SR 3.3.5.1.9 4
| |
| : b. Drywell Pressure - 1,2,3 4 B SR 3.3.5.1.3 2 < 2.19 psig High SR 3.3.5.1.8 3 SR 3.3.5.1.9 4 (continued)
| |
| (a) When associated ECCS subsystem(s) are required to be OPERABLE per LCO 3.5.2, ECCS-Shutdown.
| |
| (b) Also required to initiate the associated Diesel Generator (DG).
| |
| TSCR-120 DAEC 3.3-41 Amendment 223
| |
| | |
| ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 2 of 5)
| |
| Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS MODES REQUIRED REFERENCED OR OTHER CHANNELS FROM SPECIFIED PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE
| |
| : 2. LPCI System (continued)
| |
| : c. Reactor Steam Dome 1,2,3 4 C SR 3.3.5.1.3 2 > 363.3 psig and Pressure - Low SR 3.3.5.1.8 3 < 485.1 psig (Injection Permissive) SR 3.3.5.1.9 4
| |
| > 363.3 psig (a) (a) 4 B SR 3.3.5.1.3 2 and < 485.1 psig 4 ,5 SR 3.3.5.1.8 3 SR 3.3.5.1.9 4
| |
| : d. Reactor Vessel Shroud 1,2,3 4 B SR 3.3.5.1.1 > 40.89 inches Level - Low SR 3.3.5.1.2 SR 3.3.5.1.4 3 SR 3.3.5.1.9 4
| |
| : e. Low Pressure Coolant 1,2,3, 1 per C SR 3.3.5.1.8 3 Injection Pump (a) (a) pump SR 3.3.5.1.9 4 Start - Time Delay 4 ,5 Relay Pumps A & B > 8.8 seconds and
| |
| < 11.2 seconds
| |
| > 13.8 seconds Pumps C & D and
| |
| < 33.5 seconds
| |
| : f. Low Pressure 1,2,3, 1 per E SR 3.3.5.1.3 2 > 471.8 gpm Coolant Injection Pump (a) (a) loop SR 3.3.5.1.8 3 and Discharge Flow - Low 4 ,5 SR 3.3.5.1.9 < 3676.6 gpm 4
| |
| (Bypass)
| |
| : g. LPCI Loop Select- 1,2,3 4 C SR 3.3.5.1.1 > 112.65 inches Reactor Vessel Water SR 3.3.5.1.2 Level - Low-Low SR 3.3.5.1.6 3 SR 3.3.5.1.9 4
| |
| : h. LPCI Loop Select - 1,2,3 4 C SR 3.3.5.1.2 > 887 psig Reactor Steam Dome SR 3.3.5.1.4 3 Pressure - Low SR 3.3.5.1.9 4 (continued)
| |
| (a) When associated ECCS subsystem(s) are required to be OPERABLE per LCO 3.5.2, ECCS - Shutdown.
| |
| TSCR-120 DAEC 3.3-42 Amendment 223
| |
| | |
| ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 3 of 5)
| |
| Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE
| |
| : 2. LPCI System (continued)
| |
| : i. LPCI Loop Select - 1,2,3 4 per C SR 3.3.5.1.1 < 7.8 psid Recirculation Pump pump SR 3.3.5.1.2 Differential Pressure SR 3.3.5.1.8 3 SR 3.3.5.1.9 4
| |
| : j. LPCI Loop Select - 1,2,3 4 C SR 3.3.5.1.1 > 0.13 psid Recirculation Riser SR 3.3.5.1.2 and < 2.07 psid Differential Pressure SR 3.3.5.1.4 3 SR 3.3.5.1.9 4
| |
| : k. 4.16 kV Emergency Bus 1,2,3 2 F SR 3.3.5.1.5 2 < 3500 V Sequential Loading SR 3.3.5.1.6 3 Relay SR 3.3.5.1.9 4 (a) (a) 1 F SR 3.3.5.1.5 2 < 3500 V 4 ,5 SR 3.3.5.1.6 SR 3.3.5.1.9 3
| |
| 4
| |
| : 3. High Pressure Coolant Injection (HPCI) System
| |
| : a. Reactor Vessel Water 1, 4 B SR 3.3.5.1.1 > 112.65 inches Level - Low Low (c) (c) SR 3.3.5.1.3 2
| |
| 2 ,3 SR 3.3.5.1.6 3 SR 3.3.5.1.9 4
| |
| : b. Drywell Pressure - 1, 4 B SR 3.3.5.1.3 2 < 2.19 psig High (c) (c) SR 3.3.5.1.8 3 2 ,3 SR 3.3.5.1.9 4
| |
| : c. Reactor Vessel Water 1, 2 C SR 3.3.5.1.1 < 214.8 inches Level - High (c) (c) SR 3.3.5.1.3 2 2 ,3 SR 3.3.5.1.6 3 SR 3.3.5.1.9 4
| |
| : d. Condensate Storage 1, 2 D SR 3.3.5.1.3 2 > 11.6 inches Tank Level - Low (c) (c) SR 3.3.5.1.8 3 2 ,3 SR 3.3.5.1.9 4
| |
| (continued)
| |
| (a) When the associated ECCS subsystem(s) are required to be OPERABLE per LCO 3.5.2, ECCS - Shutdown.
| |
| (c) With reactor steam dome pressure > 150 psig.
| |
| TSCR-120 DAEC 3.3-43 Amendment 223
| |
| | |
| ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 4 of 5)
| |
| Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE
| |
| : 3. HPCI System (continued)
| |
| : e. Suppression Pool 1, 2 D SR 3.3.5.1.3 2 < 5.9 inches Water Level - High SR 3.3.5.1.8 3 (c) (c) SR 3.3.5.1.9 2 ,3 4
| |
| : f. High Pressure Coolant 1, Injection Pump (c) (c) 2 ,3 1 E SR 3.3.5.1.3 2 > 264.2 gpm Discharge Flow - Low SR 3.3.5.1.8 3 and (Bypass) SR 3.3.5.1.9 < 2025.1 gpm 4
| |
| : 4. Automatic Depressurization System (ADS) Trip Logic A
| |
| : a. Reactor Vessel Water 1, 2 G SR 3.3.5.1.1 > 38.3 inches Level - Low Low Low SR 3.3.5.1.3 2
| |
| (d) (d) 2 ,3 SR 3.3.5.1.8 3 SR 3.3.5.1.9 4
| |
| : b. Automatic 1, 1 H SR 3.3.5.1.3 2 < 125 seconds Depressurization (d) (d) SR 3.3.5.1.8 3 System Timer 2 ,3 SR 3.3.5.1.9 4
| |
| : c. Reactor Vessel Water 1, 1 G SR 3.3.5.1.1 > 166.1 inches Level - Low (d) (d) SR 3.3.5.1.3 2
| |
| (Confirmatory) 2 ,3 SR 3.3.5.1.8 3 SR 3.3.5.1.9 4
| |
| : d. Core Spray Pump 1, 2 H SR 3.3.5.1.3 2 > 114.2 psig Discharge (d) (d) SR 3.3.5.1.8 3 and Pressure - High 2 ,3 SR 3.3.5.1.9 < 177.0 psig 4
| |
| : e. Low Pressure Coolant (d) 1, (d) 4 H SR 3.3.5.1.3 2 > 103.8 psig Injection Pump 2 ,3 SR 3.3.5.1.8 and Discharge Pressure - SR 3.3.5.1.9 3 < 147.0 psig High 4 (continued)
| |
| (c) With reactor steam dome pressure > 150 psig.
| |
| (d) With reactor steam dome pressure > 100 psig.
| |
| TSCR-120 DAEC 3.3-44 Amendment No. 245
| |
| | |
| ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 5 of 5)
| |
| Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE
| |
| : 5. ADS Trip Logic B
| |
| : a. Reactor Vessel Water 1, 2 G SR 3.3.5.1.1 2 > 38.3 inches Level - Low Low Low (d) (d) SR 3.3.5.1.3 3 2 ,3 SR 3.3.5.1.8 SR 3.3.5.1.9 4
| |
| : b. Automatic 1, 1 H SR 3.3.5.1.3 2 < 125 seconds Depressurization (d) (d) SR 3.3.5.1.8 3 System Timer 2 ,3 SR 3.3.5.1.9 4
| |
| : c. Reactor Vessel Water 1, 1 G SR 3.3.5.1.1 2 > 166.1 inches Level - Low (d) (d) SR 3.3.5.1.3 (Confirmatory) 2 ,3 SR 3.3.5.1.8 3
| |
| SR 3.3.5.1.9 4
| |
| : d. Core Spray Pump 1, 2 H SR 3.3.5.1.3 2 > 114.2 psig Discharge 2
| |
| (d)
| |
| ,3 (d) SR 3.3.5.1.8 3 and Pressure - High SR 3.3.5.1.9 < 177.0 psig 4
| |
| : e. Low Pressure Coolant 1, 4 H SR 3.3.5.1.3 2 > 103.8 psig Injection Pump (d) (d) SR 3.3.5.1.8 3 and Discharge 2 ,3 SR 3.3.5.1.9 < 147.0 psig Pressure - High 4 (d) With reactor steam dome pressure > 100 psig.
| |
| TSCR-120 DAEC 3.3-45 Amendment No. 245
| |
| | |
| RCIC System Instrumentation 3.3.5.2 SURVEILLANCE REQUIREMENTS
| |
| -------------------------------------------------------NOTES--------------------------------------------------
| |
| : 1. Refer to Table 3.3.5.2-1 to determine which SRs apply for each RCIC Function.
| |
| : 2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed as follows: (a) for up to 6 hours for Functions 2 and 3; and (b) for up to 6 hours for Function 1 provided the associated Function maintains RCIC initiation capability.
| |
| SURVEILLANCE FREQUENCY SR 3.3.5.2.1 Perform CHANNEL CHECK. 24 hours SR 3.3.5.2.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.5.2.3 Perform CHANNEL CALIBRATION. 12 months INSERT 1 SR 3.3.5.2.4 Perform CHANNEL CALIBRATION. 24 months 4
| |
| SR 3.3.5.2.5 Perform LOGIC SYSTEM FUNCTIONAL 24 months TEST.
| |
| TSCR-120 DAEC 3.3-48 Amendment 223
| |
| | |
| RCIC System Instrumentation 3.3.5.2 Table 3.3.5.2-1 (page 1 of 1)
| |
| Reactor Core Isolation Cooling System Instrumentation CONDITIONS REQUIRED REFERENCED CHANNELS FROM REQUIRED SURVEILLANCE ALLOWABLE FUNCTION PER FUNCTION ACTION A.1 REQUIREMENTS VALUE
| |
| : 1. Reactor Vessel Water 4 B SR 3.3.5.2.1 112.65 inches Level - Low Low SR 3.3.5.2.2 SR 3.3.5.2.3 SR 3.3.5.2.5 4
| |
| : 2. Reactor Vessel Water 2 C SR 3.3.5.2.1 < 214.8 inches Level - High SR 3.3.5.2.2 SR 3.3.5.2.3 SR 3.3.5.2.5 4
| |
| : 3. Condensate Storage Tank 2 D SR 3.3.5.2.2 11.6 inches Level - Low SR 3.3.5.2.4 3 SR 3.3.5.2.5 4 TSCR-120 DAEC 3.3-49 Amendment 223
| |
| | |
| Primary Containment Isolation Instrumentation 3.3.6.1 SURVEILLANCE REQUIREMENTS
| |
| ----------------------------------------------------NOTES------------------------------------------------------
| |
| : 1. Refer to Table 3.3.6.1-1 to determine which SRs apply for each Primary Containment Isolation Function.
| |
| : 2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed as follows: (a) for up to 6 hours for Function 5.a; and (b) for up to 6 hours for Functions other than 5.a provided the associated Function maintains isolation capability.
| |
| SURVEILLANCE FREQUENCY SR 3.3.6.1.1 Perform CHANNEL CHECK. 12 hours SR 3.3.6.1.2 Perform CHANNEL CHECK. 24 hours 2
| |
| SR 3.3.6.1.3 Perform CHANNEL FUNCTIONAL TEST. 31 days INSERT 1 SR 3.3.6.1.4 Perform CHANNEL FUNCTIONAL TEST. 92 days 3
| |
| SR 3.3.6.1.5 Perform CHANNEL CALIBRATION. 92 days SR 3.3.6.1.6 Perform CHANNEL CALIBRATION. 184 days SR 3.3.6.1.7 Perform CHANNEL CALIBRATION. 12 months (continued)
| |
| TSCR-120 DAEC 3.3-55 Amendment No. 231
| |
| | |
| Primary Containment Isolation Instrumentation 3.3.6.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.3.6.1.8 Perform CHANNEL CALIBRATION. 24 months 4
| |
| INSERT 1 SR 3.3.6.1.9 Perform LOGIC SYSTEM FUNCTIONAL 24 months TEST.
| |
| TSCR-120 DAEC 3.3-56 Amendment No. 231
| |
| | |
| Primary Containment Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 1 of 5)
| |
| Primary Containment Isolation Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION C.1 REQUIREMENTS VALUE
| |
| : 1. Main Steam Line Isolation
| |
| : a. Reactor Vessel Water 1,2,3 2 D SR 3.3.6.1.1 2 > 38.3 inches Level - Low Low Low SR 3.3.6.1.4 SR 3.3.6.1.8 3 SR 3.3.6.1.9 4
| |
| : b. Main Steam Line 1 2 E SR 3.3.6.1.4 2 > 821 psig Pressure - Low SR 3.3.6.1.5 3 SR 3.3.6.1.9 4
| |
| : c. Main Steam Line 1,2,3 2 per D SR 3.3.6.1.1 2 < 138% rated Flow - High MSL SR 3.3.6.1.4 steam flow SR 3.3.6.1.5 3 SR 3.3.6.1.9 4
| |
| : d. Condenser 1, 2 (a)
| |
| , 2 D SR 3.3.6.1.4 2 > 7.2 inches Backpressure - High (a) SR 3.3.6.1.8 3 Hg vacuum 3 SR 3.3.6.1.9 4
| |
| : e. Main Steam Line Tunnel 1,2,3 4 D SR 3.3.6.1.2 1 < 205.1°F Temperature - High SR 3.3.6.1.4 SR 3.3.6.1.7 2 SR 3.3.6.1.9 3 4
| |
| f.. Turbine Building 1,2,3 4 D SR 3.3.6.1.2 1 < 205.1°F Temperature - High SR 3.3.6.1.4 2 SR 3.3.6.1.7 SR 3.3.6.1.9 3 4 (continued)
| |
| (a) When any turbine stop valve is greater than 90% open or when the key-locked bypass switch is in the NORM Position.
| |
| TSCR-120 DAEC 3.3-57 Amendment No. 261
| |
| | |
| Primary Containment Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 2 of 5)
| |
| Primary Containment Isolation Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION C.1 REQUIREMENTS VALUE
| |
| : 2. Primary Containment Isolation
| |
| : a. Reactor Vessel Water 1,2,3 2 H SR 3.3.6.1.1 2 > 165.6 inches Level - Low SR 3.3.6.1.4 SR 3.3.6.1.8 3
| |
| SR 3.3.6.1.9 4
| |
| : b. Drywell Pressure - High 1,2,3 2 H SR 3.3.6.1.4 2 < 2.2 psig SR 3.3.6.1.8 3 SR 3.3.6.1.9 4
| |
| : c. Offgas Vent Stack - 1 (c)
| |
| , 2(c), 1 L SR 3.3.6.1.2 1 (b)
| |
| High Radiation (c) SR 3.3.6.1.4 2 3 SR 3.3.6.1.8 SR 3.3.6.1.9 3 4
| |
| : d. Reactor Building 1,2,3 1 H SR 3.3.6.1.2 < 12.8 mR/hr Exhaust Shaft - SR 3.3.6.1.4 1
| |
| High Radiation SR 3.3.6.1.8 2 SR 3.3.6.1.9 3
| |
| : e. Refueling Floor 1,2,3 1 H SR 3.3.6.1.2 4 < 10.6 mR/hr 1
| |
| Exhaust Duct - SR 3.3.6.1.4 High Radiation SR 3.3.6.1.8 2 SR 3.3.6.1.9 3 4
| |
| : 3. High Pressure Coolant Injection (HPCI) System Isolation
| |
| : a. HPCI Steam Line Flow - 1,2,3 1 F SR 3.3.6.1.4 2 < 409 inches High SR 3.3.6.1.8 3 (inboard)
| |
| SR 3.3.6.1.9 < 110 inches 4 (outboard)
| |
| (continued)
| |
| (b) Allowable value is determined in accordance with the ODAM.
| |
| (c) During venting or purging of primary containment.
| |
| TSCR-120 DAEC 3.3-58 Amendment 223
| |
| | |
| Primary Containment Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 3 of 5)
| |
| Primary Containment Isolation Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION C.1 REQUIREMENTS VALUE
| |
| : 3. HPCI System Isolation (continued)
| |
| : b. HPCI Steam Supply Line 1,2,3 2 F SR 3.3.6.1.4 2 > 50 psig and Pressure - Low SR 3.3.6.1.8 3 < 147.1 psig SR 3.3.6.1.9 4
| |
| : c. HPCI Turbine 1,2,3 2 F SR 3.3.6.1.4 2 > 2.5 psig Exhaust Diaphragm SR 3.3.6.1.8 3 Pressure - High SR 3.3.6.1.9 4
| |
| 2
| |
| : d. Drywell Pressure - 1,2,3 1 F SR 3.3.6.1.4 < 2.2 psig High SR 3.3.6.1.8 3 SR 3.3.6.1.9 4
| |
| : e. Suppression Pool 1,2,3 1 F SR 3.3.6.1.2 1 < 153.3°F Area Ambient SR 3.3.6.1.4 2 Temperature - High SR 3.3.6.1.8 3 SR 3.3.6.1.9 4
| |
| : f. HPCI Leak Detection 1,2,3 1 F SR 3.3.6.1.4 2 N/A Time Delay SR 3.3.6.1.8 3 SR 3.3.6.1.9 4
| |
| : g. Suppression Pool 1,2,3 1 F SR 3.3.6.1.2 1 < 51.5°F Area Ventilation SR 3.3.6.1.4 Differential SR 3.3.6.1.8 2
| |
| Temperature - High SR 3.3.6.1.9 3 1 4
| |
| : h. HPCI Equipment Room 1,2,3 1 F SR 3.3.6.1.2 < 178.3°F Temperature - High SR 3.3.6.1.4 2 SR 3.3.6.1.8 3 SR 3.3.6.1.9 4
| |
| : i. HPCI Room Ventilation 1,2,3 1 F SR 3.3.6.1.2 < 51.5°F Differential SR 3.3.6.1.4 1
| |
| Temperature - High SR 3.3.6.1.8 2 SR 3.3.6.1.9 3 4
| |
| (continued)
| |
| TSCR-120 DAEC 3.3-59 Amendment No. 231
| |
| | |
| Primary Containment Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 4 of 5)
| |
| Primary Containment Isolation Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION C.1 REQUIREMENTS VALUE
| |
| : 4. Reactor Core Isolation Cooling (RCIC) System Isolation 2
| |
| : a. RCIC Steam Line 1,2,3 1 F SR 3.3.6.1.4 < 164 inches Flow - High SR 3.3.6.1.8 3 (inboard)
| |
| SR 3.3.6.1.9 4 < 159 inches (outboard) 2
| |
| : b. RCIC Steam Supply 1,2,3 2 F SR 3.3.6.1.4 3 > 50.3 psig Line Pressure - Low SR 3.3.6.1.8 SR 3.3.6.1.9 4
| |
| : c. RCIC Turbine 1,2,3 2 F SR 3.3.6.1.4 2 > 3.3 psig Exhaust Diaphragm SR 3.3.6.1.6 3 Pressure - High SR 3.3.6.1.9 4
| |
| : d. Drywell Pressure - 1,2,3 1 F SR 3.3.6.1.4 2 < 2.2 psig High SR 3.3.6.1.8 3 SR 3.3.6.1.9 4
| |
| : e. RCIC Suppression 1,2,3 1 F SR 3.3.6.1.2 1 < 153.3°F Pool Area Ambient SR 3.3.6.1.4 Temperature - High SR 3.3.6.1.8 2
| |
| SR 3.3.6.1.9 3 4
| |
| : f. RCIC Leak Detection 1,2,3 1 F SR 3.3.6.1.4 2 N/A Time Delay SR 3.3.6.1.8 3 SR 3.3.6.1.9 4
| |
| : g. RCIC Suppression 1,2,3 1 F SR 3.3.6.1.2 1 < 51.5°F Pool Area Ventilation SR 3.3.6.1.4 Differential SR 3.3.6.1.8 2
| |
| Temperature - High SR 3.3.6.1.9 3 1 4
| |
| : h. RCIC Equipment Room 1,2,3 1 F SR 3.3.6.1.2 < 178.3°F Temperature - High SR 3.3.6.1.4 2 SR 3.3.6.1.8 3 SR 3.3.6.1.9 4
| |
| : i. RCIC Room 1,2,3 1 F SR 3.3.6.1.2 1 < 51.5°F Ventilation SR 3.3.6.1.4 Differential SR 3.3.6.1.8 2 Temperature - High SR 3.3.6.1.9 3 4
| |
| (continued)
| |
| TSCR-120 DAEC 3.3-60 Amendment No. 231
| |
| | |
| Primary Containment Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 5 of 5)
| |
| Primary Containment Isolation Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION C.1 REQUIREMENTS VALUE
| |
| : 5. Reactor Water Cleanup (RWCU) System Isolation 1
| |
| : a. Differential Flow - 1,2,3 1 F SR 3.3.6.1.2 < 59 gpm High SR 3.3.6.1.4 2 SR 3.3.6.1.8 3 SR 3.3.6.1.9 4
| |
| : b. Area Temperature - High 1,2,3 1 (d) F SR 3.3.6.1.2 1 < 133.3°F SR 3.3.6.1.4 2 SR 3.3.6.1.8 SR 3.3.6.1.9 3 4
| |
| : c. Area Ventilation 1,2,3 (d) F SR 3.3.6.1.2 1 1 Differential SR 3.3.6.1.4 Temperature - High SR 3.3.6.1.8 2 SR 3.3.6.1.9 3 RWCU Pump Room 4 < 22.5°F RWCU Pump A Room < 23.5°F RWCU Pump B Room < 34.5°F RWCU Heat Exch. Room < 51.5°F (e) 4
| |
| : d. SLC System Initiation 1,2 1 I SR 3.3.6.1.9 NA
| |
| : e. Reactor Vessel Water 1,2,3 2 F SR 3.3.6.1.1 > 112.65 Level - Low Low SR 3.3.6.1.4 2 inches SR 3.3.6.1.7 3 SR 3.3.6.1.9 4
| |
| : f. Area Near TIP Room 1,2,3 1 F SR 3.3.6.1.2 1 < 115.7°F Ambient Temperature - SR 3.3.6.1.4 2 High SR 3.3.6.1.8 SR 3.3.6.1.9 3
| |
| 4
| |
| : 6. Shutdown Cooling System Isolation 2
| |
| : a. Reactor Steam Dome 1,2,3 1 F SR 3.3.6.1.4 < 152.7 psig Pressure - High SR 3.3.6.1.5 3 SR 3.3.6.1.9 4
| |
| : b. Reactor Vessel Water 3,4,5 (f) J SR 3.3.6.1.1 > 165.6 inches 2 2 Level - Low SR 3.3.6.1.4 SR 3.3.6.1.8 3 SR 3.3.6.1.9 4
| |
| : c. Drywell Pressure - 1,2,3 2 F SR 3.3.6.1.4 2 < 2.2 psig High SR 3.3.6.1.8 3 SR 3.3.6.1.9 4
| |
| : 7. Containment Cooling System Isolation
| |
| : a. Containment Pressure - 1,2,3 4 K SR 3.3.6.1.3 2 > 1.25 psig High SR 3.3.6.1.8 3 SR 3.3.6.1.9 4
| |
| (d) Each Trip System must have either an OPERABLE Function 5.b or an OPERABLE Function 5.c channel in both the RWCU pump area and in the RWCU heat exchanger area.
| |
| (e) SLC System Initiation only inputs into one of the two trip systems.
| |
| (f) Only one trip system required in MODES 4 and 5 when RHR Shutdown Cooling System integrity maintained.
| |
| TSCR-120 DAEC 3.3-61 Amendment 223
| |
| | |
| Secondary Containment Isolation Instrumentation 3.3.6.2 SURVEILLANCE REQUIREMENTS
| |
| ----------------------------------------------------NOTES-----------------------------------------------------
| |
| : 1. Refer to Table 3.3.6.2-1 to determine which SRs apply for each Secondary Containment Isolation Function.
| |
| : 2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains secondary containment isolation capability.
| |
| SURVEILLANCE FREQUENCY SR 3.3.6.2.1 Perform CHANNEL CHECK. 12 hours SR 3.3.6.2.2 Perform CHANNEL CHECK. 24 hours 2
| |
| INSERT 1 SR 3.3.6.2.3 Perform CHANNEL FUNCTIONAL TEST. 92 days 3
| |
| SR 3.3.6.2.4 Perform CHANNEL CALIBRATION. 24 months 4
| |
| SR 3.3.6.2.5 Perform LOGIC SYSTEM FUNCTIONAL 24 months TEST.
| |
| TSCR-120 DAEC 3.3-64 Amendment 223
| |
| | |
| Secondary Containment Isolation Instrumentation 3.3.6.2 Table 3.3.6.2-1 (page 1 of 1)
| |
| Secondary Containment Isolation Instrumentation APPLICABLE MODES OR REQUIRED OTHER CHANNELS SPECIFIED PER SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS TRIP SYSTEM REQUIREMENTS VALUE
| |
| : 1. Reactor Vessel Water 1,2,3, 2 SR 3.3.6.2.1 2 > 165.6 inches Level - Low (a) SR 3.3.6.2.3 3 SR 3.3.6.2.4 SR 3.3.6.2.5 4
| |
| 2
| |
| : 2. Drywell Pressure - High 1,2,3 2 SR 3.3.6.2.3 < 2.2 psig SR 3.3.6.2.4 3
| |
| SR 3.3.6.2.5 4
| |
| : 3. Reactor Building Exhaust 1,2,3, 1 SR 3.3.6.2.2 1 < 12.8 mR/hr Shaft - High Radiation (a) SR 3.3.6.2.3 2 SR 3.3.6.2.4 3 SR 3.3.6.2.5 4
| |
| : 4. Refueling Floor Exhaust 1,2,3, 1 SR 3.3.6.2.2 1 < 10.6 mR/hr Duct - High Radiation (a) SR 3.3.6.2.3 SR 3.3.6.2.4 2 SR 3.3.6.2.5 3 4
| |
| (a) During operations with a potential for draining the reactor vessel.
| |
| TSCR-120 DAEC 3.3-65 Amendment 237
| |
| | |
| LLS Instrumentation 3.3.6.3 ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and D.1 Declare the Immediately associated Completion associated LLS Time of Condition A, B, valve(s) inoperable.
| |
| or C not met.
| |
| OR Both LLS valves inoperable due to inoperable channels.
| |
| SURVEILLANCE REQUIREMENTS
| |
| -----------------------------------------------------NOTES-----------------------------------------------------
| |
| : 1. Refer to Table 3.3.6.3-1 to determine which SRs apply for each Function.
| |
| : 2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains LLS initiation capability.
| |
| SURVEILLANCE FREQUENCY SR 3.3.6.3.1 Perform CHANNEL FUNCTIONAL TEST for 92 days portion of the channel outside primary containment. INSERT 1 SR 3.3.6.3.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.6.3.3 Perform CHANNEL CALIBRATION. 92 days (continued)
| |
| TSCR-120 DAEC 3.3-67 Amendment 223
| |
| | |
| LLS Instrumentation 3.3.6.3 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.3.6.3.4 Perform CHANNEL CALIBRATION. 184 days SR 3.3.6.3.5 Perform CHANNEL CALIBRATION. 24 months 4
| |
| SR 3.3.6.3.6 Perform LOGIC SYSTEM FUNCTIONAL 24 months INSERT 1 TEST.
| |
| TSCR-120 DAEC 3.3-68 Amendment 223
| |
| | |
| LLS Instrumentation 3.3.6.3 Table 3.3.6.3-1 (page 1 of 1)
| |
| Low-Low Set Instrumentation REQUIRED CHANNELS PER SURVEILLANCE ALLOWABLE FUNCTION FUNCTION REQUIREMENTS VALUE
| |
| : 1. Reactor Vessel Steam Dome 1 per LLS valve SR 3.3.6.3.2 < 1069.21 psig Pressure - High SR 3.3.6.3.3 4 SR 3.3.6.3.6
| |
| : 2. Low-Low Set Pressure Setpoints 2 per LLS valve SR 3.3.6.3.2 Low:
| |
| SR 3.3.6.3.4 3 Open > 1014 psig SR 3.3.6.3.6 4 and < 1045 psig Close > 893.4 psig and < 925 psig High:
| |
| Open > 1019 psig and < 1050 psig Close > 893.4 psig and < 930 psig
| |
| : 3. Tailpipe High Pressure 3 per SRV SR 3.3.6.3.1 < 99 psig SR 3.3.6.3.5 3 SR 3.3.6.3.6 4
| |
| TSCR-120 DAEC 3.3-69 Amendment 223
| |
| | |
| SFU System Instrumentation 3.3.7.1 SURVEILLANCE REQUIREMENTS
| |
| -----------------------------------------------------NOTE---------------------------------------------------
| |
| When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the other channel is OPERABLE.
| |
| SURVEILLANCE FREQUENCY SR 3.3.7.1.1 Perform CHANNEL CHECK. 24 hours SR 3.3.7.1.2 Perform CHANNEL FUNCTIONAL TEST. 92 days INSERT 1 SR 3.3.7.1.3 Perform CHANNEL CALIBRATION. The 24 months Allowable Value shall be 5 mR/hr.
| |
| SR 3.3.7.1.4 Perform LOGIC SYSTEM FUNCTIONAL 24 months TEST.
| |
| TSCR-120 DAEC 3.3-71 Amendment 240
| |
| | |
| LOP Instrumentation 3.3.8.1 SURVEILLANCE REQUIREMENTS
| |
| ----------------------------------------------------NOTES-----------------------------------------------------
| |
| : 1. Refer to Table 3.3.8.1-1 to determine which SRs apply for each LOP Function.
| |
| : 2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 2 hours provided the associated Function maintains DG initiation capability.
| |
| SURVEILLANCE FREQUENCY SR 3.3.8.1.1 Perform CHANNEL FUNCTIONAL TEST. 31 days SR 3.3.8.1.2 Perform CHANNEL FUNCTIONAL TEST. 12 months INSERT 1 2
| |
| SR 3.3.8.1.3 Perform CHANNEL CALIBRATION. 12 months SR 3.3.8.1.4 Perform CHANNEL CALIBRATION. 24 months 3
| |
| SR 3.3.8.1.5 Perform LOGIC SYSTEM FUNCTIONAL 24 months TEST.
| |
| TSCR-120 DAEC 3.3-74 Amendment 223
| |
| | |
| LOP Instrumentation 3.3.8.1 Table 3.3.8.1-1 (page 1 of 1)
| |
| Loss of Power Instrumentation REQUIRED CHANNELS SURVEILLANCE ALLOWABLE FUNCTION PER BUS REQUIREMENTS VALUE
| |
| : 1. 4.16 kV Emergency Bus Undervoltage (Loss of Voltage)
| |
| : a. Bus Undervoltage 1 SR 3.3.8.1.2 1 > 595 V and SR 3.3.8.1.4 2 < 2275 V SR 3.3.8.1.5 3
| |
| : 2. 4.16 kV Emergency Bus Undervoltage (Degraded Voltage)
| |
| : a. Bus Undervoltage 4 SR 3.3.8.1.1 > 3780 V and SR 3.3.8.1.3 2 <3822 V SR 3.3.8.1.5 3
| |
| : b. Time Delay 4 SR 3.3.8.1.1 > 7.92 seconds and SR 3.3.8.1.3 2 < 8.5 seconds SR 3.3.8.1.5 3
| |
| : 3. 4.16 kV Emergency Transformer 2 SR 3.3.8.1.2 1 > 2450 V Supply Undervoltage SR 3.3.8.1.3 2 SR 3.3.8.1.5 3 TSCR-120 DAEC 3.3-75 Amendment 273
| |
| | |
| RPS Electric Power Monitoring 3.3.8.2 ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and D.1 Initiate action to fully Immediately associated Completion Time insert all insertable of Condition A or B not met control rods in core in MODE 3, 4 or 5 with any cells containing one control rod withdrawn from a or more fuel core cell containing one or assemblies.
| |
| more fuel assemblies.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.8.2.1 -------------------------NOTE---------------------------
| |
| Only required to be performed prior to entering MODE 2 or 3 from MODE 4, when in MODE 4 for 24 hours.
| |
| Perform CHANNEL FUNCTIONAL TEST. 184 days SR 3.3.8.2.2 Perform CHANNEL CALIBRATION. The 24 months Allowable Values shall be:
| |
| INSERT 1
| |
| : a. Overvoltage 132 V.
| |
| : b. Undervoltage 108 V.
| |
| : c. Underfrequency 57 Hz.
| |
| SR 3.3.8.2.3 Perform a system functional test. 24 months TSCR-120 DAEC 3.3-77 Amendment 223
| |
| | |
| Recirculation Loops Operating 3.4.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.1.1 -----------------------------NOTE---------------------------
| |
| Not required to be performed until 24 hours after both recirculation loops are in operation.
| |
| Verify recirculation pump speed mismatch with 24 hours both recirculation pumps at steady state operation is as follows:
| |
| INSERT 1
| |
| : a. The speed of the faster pump shall be 135% of the speed of the slower pump when operating at < 69.4 % RTP.
| |
| : b. The speed of the faster pump shall be 122% of the speed of the slower pump when operating at 69.4 % RTP.
| |
| SR 3.4.1.2 Verify core flow as a function of core THERMAL 24 hours POWER is outside the Exclusion Region shown in the COLR.
| |
| TSCR-120 DAEC 3.4-3 Amendment 243
| |
| | |
| Jet Pumps 3.4.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.2.1 -----------------------------NOTES-------------------------------
| |
| : 1. Not required to be performed until 4 hours after the associated recirculation loop is in operation.
| |
| : 2. Not required to be performed until 24 hours after > 21.7% RTP.
| |
| : 3. Criterion c is only applicable when pump speed is 60% rated speed.
| |
| 24 hours INSERT1 Verify at least one of the following criteria (a, b or c, as applicable) is satisfied for each operating recirculation loop:
| |
| : a. Recirculation pump flow to speed ratio differs by 5% from established patterns, and jet pump loop flow to recirculation pump speed ratio differs by 5% from established patterns.
| |
| : b. Each jet pump diffuser to lower plenum differential pressure differs by 20% from established patterns.
| |
| : c. The recirculation pump flow to speed ratio, jet pump loop flow to recirculation pump speed ratio, and jet pump diffuser to lower plenum differential pressure ratios are evaluated as being acceptable.
| |
| TSCR-120 DAEC 3.4-5 Amendment 243
| |
| | |
| SRVs and SVs 3.4.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.3.1 Verify the safety function lift setpoints of the SRVs In accordance and SVs are as follows: with the Inservice Number of Setpoint Testing Program SRVs (psig)__
| |
| 1 1110 +/- 33.0 1 1120 +/- 33.0 2 1130 +/- 33.0 2 1140 +/- 33.0 Number of Setpoint SVs (psig)__
| |
| 2 1240 +/- 36.0 Following testing, lift settings shall be within +/-
| |
| 1%.
| |
| SR 3.4.3.2 -----------------------------NOTE---------------------------
| |
| Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| Verify each SRV opens when manually 24 months INSERT 1 actuated.
| |
| TSCR-120 DAEC 3.4-7 Amendment No. 228
| |
| | |
| RCS Operational LEAKAGE 3.4.4 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.2 Verify source of 4 hours unidentified LEAKAGE increase is not service sensitive type 304 or type 316 austenitic stainless steel.
| |
| C. Required Action and C.1 Be in MODE 3. 12 hours associated Completion Time of AND Condition A or B not met. C.2 Be in MODE 4. 36 hours SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY INSERT 1 SR 3.4.4.1 Verify RCS unidentified and total LEAKAGE and 12 hours unidentified LEAKAGE increase are within limits.
| |
| TSCR-120 DAEC 3.4-9 Amendment 223
| |
| | |
| RCS Leakage Detection Instrumentation 3.4.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.5.1 Perform a CHANNEL CHECK of required 12 hours Primary Containment Air Sampling System.
| |
| SR 3.4.5.2 Perform a CHANNEL FUNCTIONAL TEST of 31 days required Primary Containment Air Sampling System instrumentation, equipment drain sump flow integrator, and floor drain sump flow integrator.
| |
| SR 3.4.5.3 Perform a CHANNEL FUNCTIONAL TEST of 92 days required equipment drain sump flow timer and floor drain sump flow timer. INSERT 1 SR 3.4.5.4 Perform a CHANNEL CALIBRATION of required 92 days Primary Containment Air Sampling System instrumentation, equipment drain sump flow integrator, and floor drain sump flow integrator.
| |
| SR 3.4.5.5 Perform a CHANNEL CALIBRATION of required 12 months equipment drain sump flow timer and floor drain sump flow timer.
| |
| TSCR-120 DAEC 3.4-12 Amendment 223
| |
| | |
| RCS Specific Activity 3.4.6 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.2.2.1 Be in MODE 3. 12 hours AND B.2.2.2 Be in MODE 4. 36 hours SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.6.1 ------------------------------NOTE-------------------------
| |
| Only required to be performed in MODE 1.
| |
| INSERT 1 Verify reactor coolant DOSE EQUIVALENT 7 days I-131 specific activity is 0.2 Ci/gm.
| |
| TSCR-120 DAEC 3.4-14 Amendment 240
| |
| | |
| RHR Shutdown Cooling System Hot Shutdown 3.4.7 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.7.1 ---------------------------NOTE---------------------------
| |
| Not required to be met until 2 hours after reactor steam dome pressure is < the RCIC Steam Supply Line Pressure - Low isolation pressure.
| |
| Verify one required RHR shutdown cooling 12 hours INSERT 1 subsystem or recirculation pump is operating.
| |
| TSCR-120 DAEC 3.4-17 Amendment 223
| |
| | |
| RHR Shutdown Cooling System Cold Shutdown 3.4.8 ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME B. No RHR shutdown B.1 Verify reactor coolant 1 hour from cooling subsystem in circulation by an discovery of no operation. alternate method. reactor coolant circulation AND AND No recirculation pump in operation. Once per 12 hours thereafter AND B.2 Monitor reactor Once per hour coolant temperature.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.8.1 Verify one required RHR shutdown cooling 12 hours INSERT 1 subsystem or one recirculation pump is operating.
| |
| TSCR-120 DAEC 3.4-19 Amendment 223
| |
| | |
| RCS P/T Limits 3.4.9 ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME C. ------------NOTE------------- C.1 Initiate action to restore Immediately Required Action C.2 parameter(s) to within shall be completed if this limits.
| |
| Condition is entered.
| |
| --------------------------------- AND Requirements of the C.2 Determine RCS is Prior to entering LCO not met in other acceptable for MODE 2 or 3.
| |
| than MODES 1, 2, operation.
| |
| and 3.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.9.1 ---------------------------NOTE--------------------------
| |
| Only required to be performed during RCS heatup and cooldown operations and RCS inservice leak and hydrostatic testing.
| |
| Verify: 30 minutes INSERT 1
| |
| : a. RCS pressure and RCS temperature are within the applicable limits in Figure 3.4.9-1.
| |
| : b. RCS heatup and cooldown rates are 20°F in any 1 hour period during inservice leak and hydrostatic testing (Curve A).
| |
| : c. RCS heatup and cooldown rates are 100°F in any 1 hour period during non-nuclear heating (Curve B) and nuclear heating (Curve C).
| |
| (continued)
| |
| TSCR-120 DAEC 3.4-21 Amendment 224
| |
| | |
| NOTE: THERE ARE NO CHANGES ON THIS PAGE. IT IS INCLUDED FOR RCS P/T Limits COMPLETENESS. 3.4.9 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.4.9.2 Verify RCS pressure and RCS temperature are Once within within the criticality limits specified in Figure 15 minutes 3.4.9-1. prior to control rod withdrawal for the purpose of achieving criticality SR 3.4.9.3 -----------------------------NOTE--------------------------
| |
| Only required to be met in MODES 1, 2, 3, and 4 during recirculation pump startup.
| |
| Verify the difference between the bottom head Once within 15 coolant temperature and the Reactor Pressure minutes prior Vessel (RPV) coolant temperature is 145°F. to each startup of a recirculation pump SR 3.4.9.4 -------------------------------NOTE-------------------------
| |
| Only required to be met in MODES 1, 2, 3, and 4 during recirculation pump startup.
| |
| Verify the difference between the reactor Once within 15 coolant temperature in the recirculation loop to minutes prior be started and the RPV coolant temperature is to each startup 50°F. of a recirculation pump (continued)
| |
| DAEC 3.4-22 Amendment 223
| |
| | |
| RCS P/T Limits 3.4.9 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.4.9.5 -----------------------------NOTE--------------------------
| |
| Only required to be performed when tensioning the reactor vessel head bolting studs.
| |
| Verify temperatures at the reactor vessel head 30 minutes flange and the shell adjacent to the head flange are 74°F.
| |
| SR 3.4.9.6 ------------------------------NOTE------------------------
| |
| Not required to be performed until 30 minutes after RCS temperature 80°F in MODE 4. INSERT 1 Verify temperatures at the reactor vessel head flange and the shell adjacent to the head 30 minutes flange are 74°F.
| |
| SR 3.4.9.7 ------------------------------NOTE-------------------------
| |
| Not required to be performed until 12 hours after RCS temperature 100°F in MODE 4.
| |
| Verify temperatures at the reactor vessel head 12 hours flange and the shell adjacent to the head flange are 74°F.
| |
| TSCR-120 DAEC 3.4-23 Amendment 223
| |
| | |
| Reactor Steam Dome Pressure 3.4.10 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.10 Reactor Steam Dome Pressure LCO 3.4.10 The reactor steam dome pressure shall be 1025 psig.
| |
| APPLICABILITY: MODES 1 and 2.
| |
| ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Reactor steam dome A.1 Restore reactor steam 15 minutes pressure not within limit. dome pressure to within limit.
| |
| B. Required Action and B.1 Be in MODE 3. 12 hours associated Completion Time not met.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY INSERT 1 SR 3.4.10.1 Verify reactor steam dome pressure is 1025 12 hours psig.
| |
| TSCR-120 DAEC 3.4-25 Amendment 223
| |
| | |
| ECCS Operating 3.5.1 ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME N. Two or more low N.1 Enter LCO 3.0.3. Immediately pressure ECCS subsystems inoperable for reasons other than Condition C or D.
| |
| OR HPCI System and two or more ADS valves inoperable.
| |
| OR HPCI System and two or more low pressure ECCS subsystems inoperable.
| |
| OR One ADS valve and two or more low pressure ECCS subsystems inoperable.
| |
| OR One ADS valve and HPCI System and one low pressure ECCS subsystem inoperable.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.1.1 Verify, for each ECCS injection/spray 31 days INSERT 1 subsystem, the piping is filled with water from the pump discharge valve to the injection valve.
| |
| (continued)
| |
| TSCR-120 DAEC 3.5-4 Amendment 223
| |
| | |
| ECCS Operating 3.5.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.5.1.2 -------------------------------NOTE-------------------------------------
| |
| The low pressure coolant injection (LPCI) system may be considered OPERABLE during alignment and operation for decay heat removal in MODE 3, if capable of being manually realigned and not otherwise inoperable.
| |
| Verify each ECCS injection/spray subsystem power 31 days operated and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position. INSERT 1 SR 3.5.1.3 Verify a 100 day supply of nitrogen exists for each ADS 31 days accumulator.
| |
| SR 3.5.1.4 Verify the following ECCS pumps develop the specified In accordance flow rate against a system head corresponding to the with the specified reactor pressure. Inservice Testing Program SYSTEM HEAD NO. CORRESPONDING OF TO A REACTOR SYSTEM FLOW RATE PUMPS PRESSURE OF Core Spray 2718 gpm 1 113 psig LPCI 4320 gpm 1 20 psig (continued)
| |
| TSCR-120 DAEC 3.5-5 Amendment 223
| |
| | |
| ECCS Operating 3.5.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.5.1.5 ----------------------------NOTE----------------------------
| |
| Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| Verify, with reactor pressure 1025 and 940 In accordance psig, the HPCI pump can develop a flow rate with the 2700 gpm against a system head Inservice Testing corresponding to reactor pressure. Program SR 3.5.1.6 -----------------------------NOTE---------------------------
| |
| Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| Verify, with reactor pressure 160 psig, the 24 months HPCI pump can develop a flow rate 2700 gpm against a system head corresponding to reactor pressure.
| |
| INSERT 1 SR 3.5.1.7 ----------------------------NOTES--------------------------
| |
| : 1. Vessel injection /spray may be excluded.
| |
| : 2. For the LPCI System, the Surveillance may be met by any series of sequential and/or overlapping steps, such that the LPCI Loop Select function is tested.
| |
| Verify each ECCS injection/spray subsystem 24 months actuates on an actual or simulated automatic initiation signal.
| |
| (continued)
| |
| TSCR-120 DAEC 3.5-6 Amendment 223
| |
| | |
| ECCS Operating 3.5.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.5.1.8 -------------------------NOTE-------------------------------
| |
| Valve actuation may be excluded.
| |
| Verify the ADS actuates on an actual or 24 months simulated automatic initiation signal.
| |
| INSERT 1 SR 3.5.1.9 --------------------------NOTE------------------------------
| |
| Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| Verify each ADS valve opens when manually 24 months actuated.
| |
| TSCR-120 DAEC 3.5-7 Amendment 223
| |
| | |
| ECCS Shutdown 3.5.2 ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action C.2 D.1 Initiate action to Immediately and associated restore Secondary Completion Time not Containment to met. OPERABLE status.
| |
| AND D.2 Initiate action to Immediately restore one Standby Gas Treatment subsystem to OPERABLE status.
| |
| AND D.3 Initiate action to Immediately restore isolation capability in each required Secondary Containment penetration flow path not isolated.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.2.1 Verify, for each required Low Pressure 12 hours INSERT 1 Coolant Injection (LPCI) subsystem, the suppression pool water level is 7.0 ft.
| |
| (continued)
| |
| TSCR-120 DAEC 3.5-9 Amendment 223
| |
| | |
| ECCS Shutdown 3.5.2 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.5.2.2 Verify, for each required Core Spray (CS) 12 hours subsystem, the:
| |
| : a. Suppression pool water level is 8.0 ft; or
| |
| : b. ---------------------NOTE-------------------------
| |
| Only one required CS subsystem may take credit for this option during OPDRVs.
| |
| Condensate storage tank water level in one CST is 11 ft or 7 ft in both CSTs. INSERT 1 SR 3.5.2.3 Verify, for each required ECCS subsystem, the 31 days piping is filled with water from the pump discharge valve to the injection valve.
| |
| SR 3.5.2.4 ---------------------------NOTE----------------------------
| |
| One LPCI subsystem may be considered OPERABLE during alignment and operation for decay heat removal if capable of being manually realigned and not otherwise inoperable.
| |
| Verify each required ECCS subsystem 31 days power operated and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position.
| |
| (continued)
| |
| TSCR-120 DAEC 3.5-10 Amendment 223
| |
| | |
| ECCS Shutdown 3.5.2 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.5.2.5 Verify each required ECCS pump develops the specified In flow rate against a system head corresponding to the accordance specified reactor pressure.
| |
| with the Inservice SYSTEM HEAD Testing NO. CORRESPONDING Program OF TO A REACTOR SYSTEM FLOW RATE PUMPS PRESSURE OF CS 2718 gpm 1 113 psig LPCI 4320 gpm 1 20 psig SR 3.5.2.6 -----------------------------------NOTES-------------------------------
| |
| : 1. Vessel injection/spray may be excluded.
| |
| : 2. For the LPCI System, the surveillance may be met by any series of sequential and/or overlapping steps, such that the LPCI Loop Select function is tested.
| |
| INSERT 1 Verify each required ECCS subsystem actuates on an 24 months actual or simulated automatic initiation signal.
| |
| TSCR-120 DAEC 3.5-11 Amendment 223
| |
| | |
| RCIC System 3.5.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.3.1 Verify the RCIC System piping is filled with 31 days water from the pump discharge valve to the injection valve. INSERT 1 SR 3.5.3.2 Verify each RCIC System power operated and 31 days automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position.
| |
| SR 3.5.3.3 -----------------------------NOTE---------------------------
| |
| Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| Verify, with reactor pressure 1025 psig and In accordance 940 psig, the RCIC pump can develop a flow with the rate 400 gpm against a system head Inservice Testing corresponding to reactor pressure. Program SR 3.5.3.4 ---------------------------NOTE-----------------------------
| |
| Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| INSERT 1 Verify, with reactor pressure 160 psig, the 24 months RCIC pump can develop a flow rate 400 gpm against a system head corresponding to reactor pressure.
| |
| (continued)
| |
| TSCR-120 DAEC 3.5-13 Amendment 223
| |
| | |
| RCIC System 3.5.3 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.5.3.5 ---------------------------NOTE----------------------------
| |
| Vessel injection may be excluded.
| |
| Verify the RCIC System actuates on an actual 24 months INSERT 1 or simulated automatic initiation signal.
| |
| TSCR-120 DAEC 3.5-14 Amendment 223
| |
| | |
| Primary Containment 3.6.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.1.1 Perform required visual examinations and In accordance leakage rate testing except for primary with the Primary containment air lock testing, in accordance Containment with the Primary Containment Leakage Rate Leakage Rate Program. Program.
| |
| SR 3.6.1.1.2 Verify suppression chamber pressure does 24 months INSERT 1 not increase at a rate > 0.009 psi per minute tested over a 10 minute period at a differential pressure of > 1.0 psid.
| |
| TSCR-120 DAEC 3.6-2 Amendment 223
| |
| | |
| Primary Containment Air Lock 3.6.1.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.2.1 ---------------------------NOTES------------------------
| |
| : 1. An inoperable air lock door does not invalidate the previous successful performance of the overall air lock leakage test.
| |
| : 2. Results shall be evaluated against acceptance criteria Applicable to SR 3.6.1.1.1.
| |
| Perform required primary containment air lock In accordance leakage rate testing in accordance with the with the Primary Primary Containment Leakage Rate Testing Containment Program. Leakage Rate Testing Program.
| |
| The acceptance criterion for air lock testing is overall air lock leakage rate 0.05 La when tested at Pa.
| |
| SR 3.6.1.2.2 Verify only one door in the primary 24 months INSERT 1 containment air lock can be opened at a time.
| |
| TSCR-120 DAEC 3.6-7 Amendment 223
| |
| | |
| PCIVs 3.6.1.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.3.1 -------------------------NOTE-----------------------------
| |
| Not required to be met when the 18 inch primary containment purge valves are open for inerting, de-inerting, pressure control, ALARA or air quality considerations for personnel entry, or Surveillances that require the valves to be open.
| |
| Verify each 18 inch primary containment purge 31 days INSERT 1 valve is closed.
| |
| SR 3.6.1.3.2 Verify continuity of the traversing incore probe (TIP) shear isolation valve explosive 31 days INSERT 1 charge.
| |
| SR 3.6.1.3.3 Verify the isolation time of each power In accordance operated automatic PCIV, except for with the MSIVs, is within limits. Inservice Testing Program SR 3.6.1.3.4 Perform leakage rate testing for each primary 184 days INSERT 1 containment purge valve with resilient seals.
| |
| AND Once within 92 days after opening the valve (continued)
| |
| TSCR-120 DAEC 3.6-13 Amendment 223
| |
| | |
| PCIVs 3.6.1.3 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.6.1.3.5 Verify the isolation time of each MSIV is In accordance with
| |
| > 3 seconds and < 5 seconds. the Inservice Testing Program SR 3.6.1.3.6 --------------------------NOTE----------------------------
| |
| For the MSIVs, this SR may be met by any series of sequential, overlapping, or total system steps, such that proper operation is verified.
| |
| INSERT 1 Verify each automatic PCIV actuates to the 24 months isolation position on an actual or simulated isolation signal.
| |
| SR 3.6.1.3.7 Verify a representative sample of reactor 24 months INSERT 1 instrumentation line EFCVs actuate on a simulated instrument line break to restrict flow.
| |
| SR 3.6.1.3.8 Remove and test the explosive squib from each In accordance with shear isolation valve of the TIP System. the Inservice Testing Program (continued)
| |
| TSCR-120 DAEC 3.6-14 Amendment No. 230
| |
| | |
| Drywell Air Temperature 3.6.1.4 3.6 CONTAINMENT SYSTEMS 3.6.1.4 Drywell Air Temperature LCO 3.6.1.4 Drywell average air temperature shall be 135°F.
| |
| APPLICABILITY: MODES 1, 2, and 3.
| |
| ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Drywell average air A.1 Restore drywell average 8 hours temperature not within air temperature to within limit. limit.
| |
| B. Required Action and B.1 Be in MODE 3. 12 hours associated Completion Time not met. AND B.2 Be in MODE 4. 36 hours SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY INSERT 1 SR 3.6.1.4.1 Verify drywell average air temperature is 24 hours within limit.
| |
| TSCR-120 DAEC 3.6-16 Amendment 223
| |
| | |
| LLS Valves 3.6.1.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.5.1 --------------------------NOTE--------------------------
| |
| Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| INSERT 1 Verify each LLS valve opens when manually 24 months actuated.
| |
| SR 3.6.1.5.2 --------------------------NOTE--------------------------
| |
| Valve actuation may be excluded.
| |
| INSERT 1 Verify the LLS System actuates on an actual 24 months or simulated automatic initiation signal.
| |
| TSCR-120 DAEC 3.6-18 Amendment 223
| |
| | |
| Reactor Building-to-Suppression Chamber Vacuum Breakers 3.6.1.6 ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME D. Two reactor building-to- D.1 Restore both valves in 1 hour suppression chamber one vacuum breaker vacuum breaker assembly to assemblies with one or OPERABLE status.
| |
| two valves inoperable for opening.
| |
| E. Required Action and E.1 Be in MODE 3. 12 hours Associated Completion Time not met. AND E.2 Be in MODE 4. 36 hours SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.6.1 -------------------------NOTES-------------------------
| |
| : 1. Not required to be met for vacuum breaker assembly valves that are open during Surveillances.
| |
| : 2. Not required to be met for vacuum breaker assembly valves open when performing their intended function.
| |
| INSERT 1 Verify each vacuum breaker assembly valve 14 days is closed.
| |
| INSERT 1 SR 3.6.1.6.2 Perform a functional test of each vacuum 92 days breaker assembly valve.
| |
| (continued)
| |
| TSCR-120 DAEC 3.6-20 Amendment 223
| |
| | |
| Reactor Building-to-Suppression Chamber Vacuum Breakers 3.6.1.6 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY INSERT 1 SR 3.6.1.6.3 Verify the opening setpoint of each 12 months vacuum breaker assembly valve is 0.614 psid.
| |
| TSCR-120 DAEC 3.6-21 Amendment 223
| |
| | |
| Suppression Chamber-to-Drywell Vacuum Breakers 3.6.1.7 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.7.1 --------------------NOTE-----------------------------
| |
| Not required to be met for vacuum breakers that are open during Surveillances.
| |
| INSERT 1 Verify each vacuum breaker is closed. 14 days INSERT 1 SR 3.6.1.7.2 Perform a functional test of each required 31 days vacuum breaker.
| |
| INSERT 1 SR 3.6.1.7.3 Verify the opening setting of each required 24 months vacuum breaker is 0.5 psid.
| |
| TSCR-120 DAEC 3.6-23 Amendment 223
| |
| | |
| Suppression Pool Average Temperature 3.6.2.1 ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME E. Suppression pool E.1 Depressurize the 12 hours average temperature reactor vessel to
| |
| > 120°F. < 200 psig.
| |
| AND E.2 Be in MODE 4. 36 hours SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY INSERT 1 SR 3.6.2.1.1 Verify suppression pool average temperature 24 hours is within the applicable limits.
| |
| AND 5 minutes when performing testing that adds heat to the suppression pool TSCR-120 DAEC 3.6-26 Amendment 223
| |
| | |
| Suppression Pool Water Level 3.6.2.2 3.6 CONTAINMENT SYSTEMS 3.6.2.2 Suppression Pool Water Level LCO 3.6.2.2 Suppression pool water level shall be 10.11 ft and 10.43 ft.
| |
| APPLICABILITY: MODES 1, 2, and 3.
| |
| ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Suppression pool water A.1 Restore suppression 2 hours level not within limits. pool water level to within limits.
| |
| B. Required Action and B.1 Be in MODE 3. 12 hours associated Completion Time not met. AND B.2 Be in MODE 4. 36 hours SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.2.2.1 Verify suppression pool water level is 24 hours INSERT 1 within limits.
| |
| TSCR-120 DAEC 3.6-27 Amendment 223
| |
| | |
| RHR Suppression Pool Cooling 3.6.2.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY INSERT 1 SR 3.6.2.3.1 Verify by administrative means each RHR 31 days suppression pool cooling subsystem manual, power operated and automatic valve in the flow path that is not locked, sealed, or otherwise secured in position is in the correct position or can be aligned to the correct position.
| |
| SR 3.6.2.3.2 Verify each RHR pump develops a flow rate In accordance 4800 gpm through the associated heat with the exchanger while operating in the suppression Inservice pool cooling mode. Testing Program TSCR-120 DAEC 3.6-29 Amendment 223
| |
| | |
| RHR Suppression Pool Spray 3.6.2.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.2.4.1 Verify by an air test that the suppression 60 months INSERT 1 pool spray header and nozzles are unobstructed.
| |
| TSCR-120 DAEC 3.6-31 Amendment 223
| |
| | |
| Primary Containment Oxygen Concentration 3.6.3.2 3.6 CONTAINMENT SYSTEMS 3.6.3.2 Primary Containment Oxygen Concentration LCO 3.6.3.2 The primary containment oxygen concentration shall be
| |
| < 4.0 volume percent.
| |
| APPLICABILITY: MODE 1 during the time period:
| |
| : a. From 24 hours after THERMAL POWER is > 15% RTP following startup, to
| |
| : b. 24 hours prior to reducing THERMAL POWER to < 15%
| |
| RTP prior to reactor shutdown.
| |
| ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Primary containment A.1 Restore oxygen 24 hours oxygen concentration not concentration to within within limit. limit.
| |
| B. Required Action and B.1 Reduce THERMAL 8 hours associated Completion POWER to 15%
| |
| Time not met. RTP.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.3.2.1 Verify primary containment oxygen 7 days INSERT 1 concentration is within limits.
| |
| TSCR-120 DAEC 3.6-34 Amendment 223
| |
| | |
| Secondary Containment 3.6.4.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.1.1 Verify all secondary containment equipment 31 days INSERT 1 hatches are closed.
| |
| SR 3.6.4.1.2 -----------------------NOTE----------------------------
| |
| Doors in high radiation areas may be verified by administrative means.
| |
| INSERT 1 Verify that either the outer door(s) or the 31 days inner door(s) in each secondary containment access opening are closed.
| |
| INSERT 1 SR 3.6.4.1.3 Verify each SBGT subsystem can maintain 24 months on a 0.25 inch of vacuum water gauge in the STAGGERED secondary containment at a flow rate 4000 TEST BASIS cfm.
| |
| TSCR-120 DAEC 3.6-36 Amendment 237
| |
| | |
| SCIV/Ds 3.6.4.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY INSERT 1 SR 3.6.4.2.1 Verify the isolation time of each power 92 days operated automatic SCIV/D is within limits.
| |
| INSERT 1 SR 3.6.4.2.2 Verify each automatic SCIV/D actuates to 24 months the isolation position on an actual or simulated actuation signal.
| |
| TSCR-120 DAEC 3.6-40 Amendment 223
| |
| | |
| SBGT System 3.6.4.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.3.1 Operate each SBGT subsystem for 10 31 days INSERT 1 continuous hours with heaters operating.
| |
| SR 3.6.4.3.2 ---------------------------NOTE---------------------------
| |
| When a SBGT subsystem is placed in an inoperable status solely for the performance of VFTP testing required by this Surveillance on the other subsystem, entry into associated Conditions and Required Actions may be delayed for up to 1 hour.
| |
| Perform required SBGT filter testing in accordance with the Ventilation Filter Testing In accordance with Program (VFTP). the VFTP SR 3.6.4.3.3 Verify each SBGT subsystem actuates on an 24 months INSERT 1 actual or simulated initiation signal.
| |
| SR 3.6.4.3.4 Verify each SBGT filter cooler bypass 24 months INSERT 1 damper can be opened and the fan started.
| |
| TSCR-120 DAEC 3.6-43 Amendment 237
| |
| | |
| RHRSW System 3.7.1 ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME D. Both RHRSW ----------------NOTE----------------
| |
| subsystems inoperable Enter applicable Conditions for reasons other than and Required Actions of Condition B. LCO 3.4.7 for RHR shutdown cooling made inoperable by RHRSW System.
| |
| D.1 Restore one RHRSW 8 hours subsystem to OPERABLE status.
| |
| E. Required Action and E.1 Be in MODE 3. 12 hours associated Completion Time not met. AND E.2 Be in MODE 4. 36 hours SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY INSERT 1 SR 3.7.1.1 Verify each RHRSW subsystem power operated 31 days and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position or can be aligned to the correct position.
| |
| TSCR-120 DAEC 3.7-2 Amendment 223
| |
| | |
| RWS System and UHS 3.7.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY INSERT 1 SR 3.7.2.1 Verify the river water level is 725.2 ft mean 24 hours sea level.
| |
| INSERT 1 SR 3.7.2.2 Verify the average river water temperature is 24 hours 95°F.
| |
| SR 3.7.2.3 -------------------------NOTE--------------------------
| |
| Not required to be performed until river depth
| |
| < 2 feet at the intake structure.
| |
| INSERT 1 Verify the river water depth is 12 inches. 7 days INSERT 1 SR 3.7.2.4 Verify each RWS subsystem power operated 31 days and automatic valve in the flow paths servicing safety related systems or components, that is not locked, sealed, or otherwise secured in position, is in the correct position.
| |
| INSERT 1 SR 3.7.2.5 Verify the river water depth 12 inches. 92 days INSERT 1 SR 3.7.2.6 Verify each RWS subsystem actuates on an 24 months actual or simulated initiation signal.
| |
| TSCR-120 DAEC 3.7-4 Amendment No. 272
| |
| | |
| ESW System 3.7.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.3.1 -------------------------NOTE--------------------------
| |
| Isolation of flow to individual components does not render ESW System inoperable.
| |
| Verify each ESW subsystem power operated 31 days INSERT 1 and automatic valve in the flow paths servicing safety related systems or components, that is not locked, sealed, or otherwise secured in position, is in the correct position.
| |
| INSERT 1 SR 3.7.3.2 Verify each ESW subsystem actuates on an 24 months actual or simulated initiation signal.
| |
| TSCR-120 DAEC 3.7-6 Amendment 223
| |
| | |
| SFU System 3.7.4 ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME F. Both SFU subsystems ----------------NOTE----------------
| |
| inoperable during LCO 3.0.3 is not applicable.
| |
| movement of irradiated -----------------------------------------
| |
| fuel assembles in the secondary F.1 Suspend movement of Immediately containment, during irradiated fuel assemblies CORE ALTERATIONS, in the secondary or during OPDRVs. containment.
| |
| OR AND One or more SFU F.2 Suspend CORE Immediately subsystems inoperable ALTERATIONS.
| |
| due to an inoperable CBE boundary during AND movement of irradiated fuel assemblies in the F.3 Initiate action to suspend Immediately secondary OPDRVs.
| |
| containment, during CORE ALTERATIONS, or during OPDRVs.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY INSERT 1 SR 3.7.4.1 Operate each SFU subsystem for 31 days 15 minutes.
| |
| SR 3.7.4.2 Perform required SFU filter testing in In accordance with accordance with the Ventilation Filter Testing the VFTP Program (VFTP).
| |
| (continued)
| |
| TSCR-120 DAEC 3.7-9 Amendment No. 269
| |
| | |
| SFU System 3.7.4 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY INSERT 1 SR 3.7.4.3 Verify each SFU subsystem actuates on an 24 months actual or simulated initiation signal.
| |
| SR 3.7.4.4 Perform required CBE unfiltered air inleakage In accordance testing in accordance with the Control Building with the Envelope Habitability Program. Control Building Envelope Habitability Program TSCR-120 DAEC 3.7-10 Amendment 269
| |
| | |
| CBC System 3.7.5 ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME E. Required Action and ------------------NOTE---------------
| |
| associated Completion LCO 3.0.3 is not applicable.
| |
| Time of Condition B not -----------------------------------------
| |
| met during movement E.1 Suspend movement Immediately of irradiated fuel of irradiated fuel assemblies in the assemblies in the secondary containment, secondary during CORE containment.
| |
| ALTERATIONS, or during OPDRVs. AND E.2 Suspend CORE Immediately ALTERATIONS.
| |
| AND E.3 Initiate action to Immediately suspend OPDRVs.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.5.1 Verify each CBC subsystem has the 92 days INSERT 1 capability to remove the available heat load.
| |
| TSCR-120 DAEC 3.7-13 Amendment 267
| |
| | |
| Main Condenser Offgas 3.7.6 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.6.1 -----------------------------NOTE--------------------------
| |
| Not required to be performed until 31 days after any main steam line not isolated and SJAE in operation.
| |
| Verify the gross gamma activity rate of the 31 days INSERT 1 noble gases is 1.0 Ci/second after decay of 30 minutes. AND Once within 4 hours after a 50% increase in the nominal steady state fission gas release after factoring out increases due to changes in THERMAL POWER level TSCR-120 DAEC 3.7-15 Amendment 223
| |
| | |
| Main Turbine Bypass System 3.7.7 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.7.1 Verify one complete cycle of each main 92 days INSERT 1 turbine bypass valve.
| |
| SR 3.7.7.2 Perform a system functional test. 24 months INSERT 1 INSERT 1 SR 3.7.7.3 Verify the TURBINE BYPASS SYSTEM 24 months RESPONSE TIME is within limits.
| |
| TSCR-120 DAEC 3.7-17 Amendment No. 239
| |
| | |
| Spent Fuel Storage Pool Water Level 3.7.8 3.7 PLANT SYSTEMS 3.7.8 Spent Fuel Storage Pool Water Level LCO 3.7.8 The spent fuel storage pool water level shall be 36 ft.
| |
| APPLICABILITY: During movement of irradiated fuel assemblies in the spent fuel storage pool.
| |
| ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Spent fuel storage A.1 -----------NOTE----------
| |
| pool water level not LCO 3.0.3 is not within limit. applicable.
| |
| Suspend movement of Immediately irradiated fuel assemblies in the spent fuel storage pool.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.8.1 Verify the spent fuel storage pool water 7 days INSERT 1 level is 36 ft.
| |
| TSCR-120 DAEC 3.7-18 Amendment 223
| |
| | |
| CB/SBGT Instrument Air System 3.7.9 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.9.1 Operate each CB/SBGT Instrument Air 31 days compressor for 20 minutes.
| |
| INSERT 1 SR 3.7.9.2 Verify each CB/SBGT Instrument Air 92 days subsystem actuates on an actual or simulated initiation signal and maintains air pressure 75 psig in the receiver.
| |
| TSCR-120 DAEC 3.7-20 Amendment No. 227
| |
| | |
| AC Sources Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY INSERT 1 SR 3.8.1.1 Verify correct breaker alignment and indicated 7 days power availability for each offsite circuit.
| |
| SR 3.8.1.2 ------------------------NOTES-----------------------------
| |
| : 1. All DG starts may be preceded by an engine prelube period and followed by a warmup period prior to loading.
| |
| : 2. A modified DG start involving idling and gradual acceleration to synchronous speed may be used for this SR as recommended by the manufacturer.
| |
| When modified start procedures are not used, the time, voltage, and frequency tolerances of SR 3.8.1.7 must be met.
| |
| : 3. When a DG is placed in an inoperable status solely for the performance of testing required by Required Actions B.3 or B.4, entry into associated Conditions and Required Actions may be delayed for up to 2 hours.
| |
| Verify each DG starts from standby conditions and achieves steady state voltage 3744v 31 days INSERT 1 and 4576v and frequency 59.5Hz and 60.5Hz.
| |
| (continued)
| |
| TSCR-120 DAEC 3.8-5 Amendment 223
| |
| | |
| AC Sources Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.8.1.3 -------------------------NOTES----------------------------
| |
| : 1. DG loadings may include gradual loading as recommended by the manufacturer.
| |
| : 2. Momentary transients outside the load range do not invalidate this test.
| |
| : 3. This Surveillance shall be conducted on only one DG at a time.
| |
| : 4. This SR shall be preceded by and immediately follow, without shutdown, a successful performance of SR 3.8.1.2 or SR 3.8.1.7.
| |
| Verify each DG is synchronized and loaded 31 days INSERT 1 and operates for 60 minutes at a load 2750kw and 2950kw.
| |
| INSERT 1 SR 3.8.1.4 Verify each day tank contains 220 gal of 31 days fuel oil.
| |
| INSERT 1 SR 3.8.1.5 Check for the presence of water in the fuel oil in 31 days each day tank and remove water as necessary.
| |
| (continued)
| |
| TSCR-120 DAEC 3.8-6 Amendment 223
| |
| | |
| AC Sources Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY INSERT 1 SR 3.8.1.6 Verify the fuel oil transfer system operates to 31 days transfer fuel oil from storage tank to the day tank.
| |
| SR 3.8.1.7 -------------------------NOTE------------------------------
| |
| All DG starts may be preceded by an engine prelube period.
| |
| INSERT 1 Verify each DG starts from standby condition 184 days and achieves:
| |
| : a. in 10 seconds, voltage 3744V and frequency 59.5Hz; and
| |
| : b. steady state, voltage 3744V and 4576V and frequency 59.5Hz and 60.5Hz.
| |
| SR 3.8.1.8 ----------------------------NOTE----------------------------
| |
| The Surveillance shall not be performed in MODE 1 or 2. However, credit may be taken for unplanned events that satisfy this SR.
| |
| Verify automatic slow transfer of AC power 24 months INSERT 1 supply from the Startup Transformer to the Standby Transformer.
| |
| (continued)
| |
| TSCR-120 DAEC 3.8-7 Amendment 225
| |
| | |
| AC Sources Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.8.1.9 ----------------------------NOTE---------------------------
| |
| This Surveillance shall not be performed in MODE 1 or 2. However, credit may be taken for unplanned events that satisfy this SR.
| |
| Verify each DG rejects a load greater than or 24 months INSERT 1 equal to its associated single largest post-accident load, and:
| |
| : a. Following load rejection, the frequency is 64.5Hz.
| |
| : b. Within 1.3 seconds following load rejection, the voltage is 3744V and 4576V.
| |
| : c. Within 3.9 seconds following load rejection, the frequency is 59.5Hz and 60.5Hz.
| |
| SR 3.8.1.10 ----------------------------NOTE---------------------------
| |
| This Surveillance shall not be performed in MODE 1, 2 or 3. However, credit may be taken for unplanned events that satisfy this SR.
| |
| Verify each DGs automatic trips are bypassed 24 months INSERT 1 on an actual or simulated Loss of Offsite Power (LOOP) signal or on an actual or simulated ECCS initiation signal except:
| |
| : a. Engine overspeed; and
| |
| : b. Generator lockout.
| |
| (continued)
| |
| TSCR-120 DAEC 3.8-8 Amendment 223
| |
| | |
| AC Sources Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.8.1.11 -----------------------------NOTE--------------------------------
| |
| This Surveillance shall not be performed in MODE 1, 2 or 3. However, credit may be taken for unplanned events that satisfy this SR.
| |
| INSERT 1 Verify under manual control each DG: 24 months
| |
| : a. Synchronizes with offsite power source while loaded with emergency loads upon a simulated restoration of offsite power;
| |
| : b. Transfers loads to offsite power source; and
| |
| : c. Returns to ready-to-load operation.
| |
| SR 3.8.1.12 -----------------------NOTE-----------------------------------
| |
| This Surveillance shall not be performed in MODE 1, 2 or 3. However, credit may be taken for unplanned events that satisfy this SR.
| |
| INSERT 1 Verify interval between each sequenced load 24 months block is 2 seconds.
| |
| (continued)
| |
| TSCR-120 DAEC 3.8-9 Amendment 223
| |
| | |
| AC Sources Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.8.1.13 -------------------------NOTES---------------------------
| |
| : 1. All DG starts may be preceded by an engine prelube period.
| |
| : 2. This Surveillance shall not be performed in MODE 1, 2, or 3. However, credit may be taken for unplanned events that satisfy this SR.
| |
| INSERT 1 Verify, on an actual or simulated loss of offsite 24 months power signal in conjunction with an actual or simulated ECCS initiation signal:
| |
| : a. De-energization of essential buses;
| |
| : b. Load shedding from essential buses; and
| |
| : c. DG auto-start from standby condition and:
| |
| : 1. energizes permanently connected loads in 10 seconds,
| |
| : 2. energizes auto-connected emergency loads in the proper timed sequence,
| |
| : 3. achieves steady state voltage 3744V and 4576V,
| |
| : 4. achieves steady state frequency 59.5Hz and 60.5Hz, and
| |
| : 5. supplies permanently connected and auto-connected emergency loads for 5 minutes.
| |
| TSCR-120 DAEC 3.8-10 Amendment 223
| |
| | |
| Diesel Fuel Oil, Lube Oil, and Starting Air 3.8.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY INSERT 1 SR 3.8.3.1 Verify fuel oil storage tank contains 31 days 36,317 gal of fuel.
| |
| INSERT 1 SR 3.8.3.2 Verify lube oil inventory is 257 gal for each DG. 31 days SR 3.8.3.3 Verify fuel oil properties of new and stored fuel In accordance oil are tested in accordance with, and with the Diesel maintained within the limits of, the Diesel Fuel Fuel Oil Testing Oil Testing Program. Program 31 days INSERT 1 SR 3.8.3.4 Verify required air start receiver pressure is 150 psig.
| |
| SR 3.8.3.5 Check for the presence of water in the fuel oil in 31 days INSERT 1 the fuel oil storage tank and remove water as necessary.
| |
| TSCR-120 DAEC 3.8-16 Amendment 223
| |
| | |
| DC Sources Operating 3.8.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.4.1 Verify battery terminal voltage is 126 V on 7 days INSERT 1 float charge for the 125 VDC battery and 252 V for the 250 VDC battery.
| |
| SR 3.8.4.2 Verify no visible corrosion at battery terminals 92 days INSERT 1 and connectors.
| |
| OR Verify battery connection resistance within limits.
| |
| SR 3.8.4.3 Verify battery cells, cell plates, and racks show 12 months INSERT 1 no visual indication of physical damage or abnormal deterioration that could degrade battery performance.
| |
| SR 3.8.4.4 Remove visible corrosion and verify battery cell to 12 months INSERT 1 cell and terminal connections are coated with anti-corrosion material.
| |
| INSERT 1 SR 3.8.4.5 Verify battery connection resistance within limits. 12 months (continued)
| |
| TSCR-120 DAEC 3.8-18 Amendment 223
| |
| | |
| DC Sources Operating 3.8.4 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY
| |
| -------------------------NOTE--------------------------------
| |
| This Surveillance shall not be performed on the required battery chargers in MODE 1, 2 or 3.
| |
| However, credit may be taken for unplanned events that satisfy this SR.
| |
| SR 3.8.4.6 Verify each required battery charger supplies 24 months INSERT 1 300 amps at 129 V for the 125 VDC subsystem and 200 amps at 258 V for the 250 VDC subsystem.
| |
| SR 3.8.4.7 --------------------------NOTES-----------------------------
| |
| : 1. The modified performance discharge test in SR 3.8.4.8 may be performed in lieu of the service test in SR 3.8.4.7.
| |
| : 2. This Surveillance shall not be performed in MODE 1, 2, or 3. However, credit may be taken for unplanned events that satisfy this SR.
| |
| Verify battery capacity is adequate to supply, 24 months INSERT 1 and maintain in OPERABLE status, the required emergency loads for the design duty cycle when subjected to a battery service test.
| |
| (continued)
| |
| TSCR-120 DAEC 3.8-19 Amendment 223
| |
| | |
| DC Sources Operating 3.8.4 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.8.4.8 ---------------------------NOTE----------------------------
| |
| This Surveillance shall not be performed in MODE 1, 2, or 3. However, credit may be taken for unplanned events that satisfy this SR.
| |
| 60 months INSERT 1 Verify battery capacity is 80% of the manufacturers rating when subjected to a performance discharge test or a modified performance discharge test. AND 12 months when battery shows degradation or has reached 85% of expected life with capacity
| |
| < 100% of manufacturers rating AND 24 months when battery has reached 85% of the expected life with capacity 100% of manufacturers rating TSCR-120 DAEC 3.8-20 Amendment 223
| |
| | |
| Battery Cell Parameters 3.8.6 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY INSERT 1 SR 3.8.6.1 Verify battery cell parameters meet Table 7 days 3.8.6-1 Category A limits.
| |
| SR 3.8.6.2 Verify battery cell parameters meet Table 92 days INSERT 1 3.8.6-1 Category B limits.
| |
| AND Once within 24 hours after battery discharge
| |
| < 110 V for 125 V and < 220 V for 250 V AND Once within 24 hours after battery overcharge
| |
| > 150 V for 125 V and > 300 V for 250 V SR 3.8.6.3 Verify average electrolyte temperature of 92 days INSERT 1 representative cells is 65°F for each battery.
| |
| TSCR-120 DAEC 3.8-25 Amendment 223
| |
| | |
| Distribution Systems Operating 3.8.7 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.7.1 Verify correct breaker alignments and 7 days INSERT 1 indicated power availability to required AC and DC electrical power distribution subsystems.
| |
| SR 3.8.7.2 Verify proper coordination of the LPCI Swing 24 months INSERT 1 Bus circuit breakers.
| |
| TSCR-120 DAEC 3.8-29 Amendment 223
| |
| | |
| Distribution Systems Shutdown 3.8.8 ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2.4 Initiate actions to Immediately restore required AC and DC electircal power distribution subsytems to OPERABLE status.
| |
| AND A.2.5 Declare associated Immediately required shutdown cooling subsystem(s) inoperable.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.8.1 Verify correct breaker alignments and 7 days INSERT 1 indicated power availability to required AC and DC electrical power distribution subsytems.
| |
| TSCR-120 DAEC 3.8-31 Amendment 223
| |
| | |
| Refueling Equipment Interlocks 3.9.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.1.1 Perform CHANNEL FUNCTIONAL TEST on 7 days INSERT 1 each of the following required refueling equipment interlock inputs:
| |
| : a. All-rods-in,
| |
| : b. Refuel platform position,
| |
| : c. Refuel platform fuel grapple, fuel loaded,
| |
| : d. Refuel platform fuel grapple fully retracted position,
| |
| : e. Refuel platform frame mounted hoist, fuel loaded, and
| |
| : f. Refuel platform monorail mounted hoist, fuel loaded.
| |
| TSCR-120 DAEC 3.9-2 Amendment 223
| |
| | |
| Refuel Position One-Rod-Out Interlock 3.9.2 3.9 REFUELING OPERATIONS 3.9.2 Refuel Position One-Rod-Out Interlock LCO 3.9.2 The refuel position one-rod-out interlock shall be OPERABLE.
| |
| APPLICABILITY: MODE 5 with the reactor mode switch in the Refuel position and any control rod withdrawn.
| |
| ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Refuel position one-rod- A.1 Suspend control rod Immediately out interlock inoperable. withdrawal.
| |
| AND A.2. Initiate action to fully Immediately insert all insertable control rods in core cells containing one or more fuel assemblies.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.2.1 Verify reactor mode switch locked in Refuel 12 hours INSERT 1 position.
| |
| (continued)
| |
| TSCR-120 DAEC 3.9-3 Amendment 223
| |
| | |
| Refuel Position One-Rod-Out Interlock 3.9.2 SURVEILLANCE REQUIREMENTS (continued)
| |
| FREQUENCY SURVEILLANCE SR 3.9.2.2 -------------------------NOTE------------------------------
| |
| Not required to be performed until 1 hour after any control rod is withdrawn.
| |
| Perform CHANNEL FUNCTIONAL TEST. 7 days INSERT 1 TSCR-120 DAEC 3.9-4 Amendment 223
| |
| | |
| Control Rod Position 3.9.3 3.9 REFUELING OPERATIONS 3.9.3 Control Rod Position LCO 3.9.3 All control rods shall be fully inserted.
| |
| APPLICABILITY: When loading fuel assemblies into the core.
| |
| ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more control A.1 Suspend loading fuel Immediately rods not fully inserted. assemblies into the core.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.3.1 Verify all control rods are fully inserted. 12 hours INSERT 1 TSCR-120 DAEC 3.9-5 Amendment 223
| |
| | |
| Control Rod OPERABILITY Refueling 3.9.5 3.9 REFUELING OPERATIONS 3.9.5 Control Rod OPERABILITY Refueling LCO 3.9.5 Each withdrawn control rod shall be OPERABLE.
| |
| APPLICABILITY: MODE 5.
| |
| ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more withdrawn A.1 Initiate action to fully Immediately control rods inoperable. insert inoperable withdrawn control rods.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.5.1 ------------------------NOTE-----------------------------
| |
| Not required to be performed until 7 days after the control rod is withdrawn.
| |
| Insert each withdrawn control rod at least one 7 days INSERT 1 notch.
| |
| INSERT 1 SR 3.9.5.2 Verify each withdrawn control rod scram 7 days accumulator pressure is 940 psig.
| |
| TSCR-120 DAEC 3.9-8 Amendment 223
| |
| | |
| RPV Water Level 3.9.6 3.9 REFUELING OPERATIONS 3.9.6 Reactor Pressure Vessel (RPV) Water Level LCO 3.9.6 RPV water level shall be 23 ft above the top of the irradiated fuel assemblies seated within the RPV.
| |
| APPLICABILITY: During movement of irradiated fuel assemblies within the RPV, During movement of new fuel assemblies or handling of control rods within the RPV, when irradiated fuel assemblies are seated within the RPV.
| |
| ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. RPV water level not A.1 Suspend movement of Immediately within limit. fuel assemblies and handling of control rods within the RPV.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.6.1 Verify RPV water level is 23 ft above the top 24 hours INSERT 1 of the irradiated fuel assemblies seated within the RPV.
| |
| TSCR-120 DAEC 3.9-9 Amendment 223
| |
| | |
| RHRLow Water Level 3.9.8 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.8.1 Verify one RHR shutdown cooling 12 hours INSERT 1 subsystem is operating.
| |
| TSCR-120 DAEC 3.9-15 Amendment 223
| |
| | |
| Reactor Mode Switch Interlock Testing 3.10.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A (continued) A.3.1 Place the reactor mode 1 hour switch in the Shutdown position.
| |
| OR A.3.2 -----------NOTE--------------
| |
| Only applicable in MODE 5.
| |
| Place the reactor mode 1 hour switch in the Refuel position.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.10.2.1 Verify all control rods are fully inserted in core 12 hours INSERT 1 cells containing one or more fuel assemblies.
| |
| SR 3.10.2.2 Verify no CORE ALTERATIONS are in progress. 24 hours INSERT 1 TSCR-120 DAEC 3.10-5 Amendment 223
| |
| | |
| Single Control Rod Withdrawal Hot Shutdown 3.10.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.10.3.1 Perform the applicable SRs for the required LCOs. According to the applicable SRs SR 3.10.3.2 ----------------------------NOTE------------------------------
| |
| Not required to be met if SR 3.10.3.1 is satisfied for LCO 3.10.3.d.1 requirements.
| |
| INSERT 1 Verify all control rods, other than the control rod 24 hours being withdrawn, in a five by five array centered on the control rod being withdrawn, are disarmed.
| |
| SR 3.10.3.3 Verify all control rods, other than the control rod 24 hours INSERT 1 being withdrawn, are fully inserted.
| |
| TSCR-120 DAEC 3.10-8 Amendment 223
| |
| | |
| Single Control Rod Withdrawal Cold Shutdown 3.10.4 ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME B. One or more of the B.1 Suspend withdrawal of Immediately above requirements the control rod and not met with the removal of associated affected control rod not CRD.
| |
| insertable.
| |
| AND B.2.1 Initiate action to fully Immediately insert all control rods.
| |
| OR Immediately B.2.2 Initiate action to satisfy the requirements of this LCO.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.10.4.1 Perform the applicable SRs for the required According to the LCOs. applicable SRs SR 3.10.4.2 ------------------------------NOTE-------------------------
| |
| Not required to be met if SR 3.10.4.1 is satisfied for LCO 3.10.4.c.1 requirements.
| |
| INSERT 1 Verify all control rods, other than the control 24 hours rod being withdrawn, in a five by five array centered on the control rod being withdrawn, are disarmed.
| |
| (continued)
| |
| TSCR-120 DAEC 3.10-11 Amendment 223
| |
| | |
| Single Control Rod Withdrawal Cold Shutdown 3.10.4 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.10.4.3 Verify all control rods, other than the control rod 24 hours INSERT 1 being withdrawn, are fully inserted.
| |
| SR 3.10.4.4 ------------------------NOTE------------------------------
| |
| Not required to be met if SR 3.10.4.1 is satisfied for LCO 3.10.4.b.1 requirements.
| |
| Verify a control rod withdrawal block is 24 hours INSERT 1 inserted.
| |
| TSCR-120 DAEC 3.10-12 Amendment 223
| |
| | |
| Single CRD Removal Refueling 3.10.5 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2.1 Initiate action to fully Immediately insert all control rods.
| |
| OR A.2.2 Initiate action to Immediately satisfy the requirements of this LCO.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY INSERT 1 SR 3.10.5.1 Verify all control rods, other than the control rod 24 hours withdrawn for the removal of the associated CRD, are fully inserted.
| |
| SR 3.10.5.2 Verify all control rods, other than the control rod 24 hours INSERT 1 withdrawn for the removal of the associated CRD, in a five by five array centered on the control rod withdrawn for the removal of the associated CRD, are disarmed.
| |
| SR 3.10.5.3 Verify a control rod withdrawal block is inserted. 24 hours INSERT 1 SR 3.10.5.4 Perform SR 3.1.1.1. According to SR 3.1.1.1 (continued)
| |
| TSCR-120 DAEC 3.10-14 Amendment 223
| |
| | |
| Single CRD Removal Refueling 3.10.5 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.10.5.5 Verify no other CORE ALTERATIONS are in 24 hours INSERT 1 progress.
| |
| TSCR-120 DAEC 3.10-15 Amendment 223
| |
| | |
| Multiple Control Rod Withdrawal Refueling 3.10.6 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.3.1 Initiate action to fully Immediately insert all control rods in core cells containing one or more fuel assemblies.
| |
| OR Immediately A.3.2 Initiate action to satisfy the requirements of this LCO.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.10.6.1 Verify the four fuel assemblies are removed 24 hours INSERT 1 from core cells associated with each control rod or CRD removed.
| |
| SR 3.10.6.2 Verify all other control rods in core cells 24 hours INSERT 1 containing one or more fuel assemblies are fully inserted.
| |
| SR 3.10.6.3 ----------------------------NOTE-------------------------
| |
| Only required to be met during fuel loading.
| |
| Verify fuel assemblies being loaded are in 24 hours INSERT 1 compliance with an approved reload sequence.
| |
| TSCR-120 DAEC 3.10-17 Amendment 223
| |
| | |
| SDM Test Refueling 3.10.8 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.10.8.1 Perform the MODE 2 applicable SRs for LCO According to the 3.3.1.1, Functions 2.a and 2.d of Table applicable SRs 3.3.1.1-1.
| |
| SR 3.10.8.2 ----------------------------NOTE--------------------------
| |
| Not required to be met if SR 3.10.8.3 satisfied.
| |
| Perform the MODE 2 applicable SRs for According to the LCO 3.3.2.1, Function 2 of Table 3.3.2.1-1. applicable SRs SR 3.10.8.3 ----------------------------NOTE--------------------------
| |
| Not required to be met if SR 3.10.8.2 satisfied.
| |
| Verify movement of control rods is in During control compliance with the approved control rod rod movement sequence for the SDM test by a second licensed operator or other qualified member of the technical staff.
| |
| INSERT 1 SR 3.10.8.4 Verify no other CORE ALTERATIONS are in 12 hours progress.
| |
| (continued)
| |
| TSCR-120 DAEC 3.10-22 Amendment 223
| |
| | |
| SDM Test Refueling 3.10.8 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.10.8.5 Verify each withdrawn control rod does not Each time the go to the withdrawn overtravel position. control rod is withdrawn to full out position AND Prior to satisfying LCO 3.10.8.c requirement after work on control rod or CRD System that could affect coupling SR 3.10.8.6 Verify CRD charging water header pressure 7 days INSERT 1 970 psig.
| |
| TSCR-120 DAEC 3.10-23 Amendment 223
| |
| | |
| Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.13 Control Building Envelope Habitability Program (continued)
| |
| : c. Requirements for (i) determining the unfiltered air inleakage past the CBE boundary into the CBE in accordance with the testing methods and at the Frequencies specified in Sections C.1 and C.2 of Regulatory Guide 1.197, Demonstrating Control Room Envelope Integrity at Nuclear Power Reactors, Revision 0, May 2003, and (ii) assessing CBE 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 CBE pressure relative to all external areas adjacent to the CBE boundary during the pressurization mode of operation by one subsystem of the SFU System, operating at the flow Staggered Test Basis
| |
| * rate required by the VFTP, at a Frequency of 24 months on a STAGGERED TEST BASIS. The results shall be trended and used as part of the 24 month assessment of the CBE boundary.
| |
| : e. The quantitative limits on unfiltered air inleakage into the CBE. These limits shall be stated in a manner to allow direct comparison to the unfiltered air inleakage measured by the testing described in paragraph c. The unfiltered air inleakage limit for radiological challenges is the inleakage flow rate assumed in the licensing basis analyses of DBA consequences. Unfiltered air leakage limits for hazardous chemicals must ensure that the exposure of CBE occupants to these hazards will be within the assumptions in the licensing basis.
| |
| : f. The provisions of SR 3.0.2 are applicable to the INSERT 2 Frequencies for assessing CBE habitability, determining CBE unfiltered inleakage, and measuring CBE pressure and assessing the CBE boundary as required by paragraphs c and d, respectively.
| |
| * A Staggered Test Basis shall consist of the testing of one of the systems, subsystems, channels, or other designated components during the interval specified by the Surveillance Frequency, so that all systems, subsystems, channels, or other designated components are tested during n Surveillance Frequency intervals, where n is the total number of systems, subsystems, channels, or other designated components in the associated function.
| |
| TSCR-120 DAEC 5.0-18a Amendment No. 269
| |
| | |
| Attachment 4 To NG-11-0037 PROPOSED TECHNICAL SPECIFICATION BASES CHANGES (MARK-UPS - FOR INFORMATION ONLY) 158 Pages to Follow
| |
| | |
| Control Rod OPERABILITY B 3.1.3 BASES ACTIONS E.1 (continued)
| |
| If any Required Action and associated Completion Time of Condition A, C, or D are not met, or there are nine or more inoperable control rods, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours. This ensures all insertable control rods are inserted and places the reactor in a condition that does not require the active function (i.e., scram) of the control rods. The number of control rods permitted to be inoperable when operating above 10% RTP (e.g., no CRDA considerations) could be more than the value specified, but the occurrence of a large number of inoperable control rods could be indicative of a generic problem, and investigation and resolution of the potential problem should be undertaken. The allowed Completion Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 from full power in an orderly manner and without challenging plant systems.
| |
| SURVEILLANCE SR 3.1.3.1 REQUIREMENTS The position of each control rod must be determined to ensure adequate information on control rod position is available to the operator for determining control rod OPERABILITY and controlling rod patterns. Control rod position may be determined by the use of OPERABLE position indicators, by moving control rods to a position with an OPERABLE indicator, by use of TIP traces, by alternate rod position determination methods, or by the use of other appropriate methods. The 24 hour Frequency of this SR is based on operating experience related to expected changes in The Surveillance control rod position and the availability of control rod position Frequency is controlled indications in the control room.
| |
| under the Surveillance Frequency Control SR 3.1.3.2 Program.
| |
| Control rod insertion capability is demonstrated by inserting each partially or fully withdrawn control rod at least one notch and observing that the control rod moves. The control rod may then be returned to its original position. This ensures the control rod is not stuck and is free to insert on a scram signal. These Surveillances are not required when THERMAL POWER is less (continued) 120 DAEC B 3.1-20 TSCR-098
| |
| | |
| Control Rod OPERABILITY B 3.1.3 BASES SURVEILLANCE SR 3.1.3.2 (continued)
| |
| REQUIREMENTS than or equal to 20% RTP since the notch insertions may not be compatible with the requirements of the Banked Position Withdrawal Sequence (BPWS) (LCO 3.1.6) and the RWM (LCO 3.3.2.1). Partially and fully withdrawn control rods are periodically tested at a 31 day Frequency, based on the potential power The Surveillance reduction required to allow the control rod movement.
| |
| Furthermore, the 31 day Frequency takes into account operating Frequency is controlled experience related to changes in CRD performance. At any time, under the Surveillance if a control rod is immovable (e.g., due to an inoperable insert or Frequency Control withdrawn solenoid valve), a determination of that control rod's Program. ability to be moved with scram pressure OPERABILITY must be made and appropriate action taken.
| |
| This SR is modified by a Note that allows 31 days after withdrawal of the control rod and increasing power to above 20% RTP, to perform the Surveillance. This acknowledges that the control rod must be first withdrawn and THERMAL POWER must be increased to above 20% RTP before performance of the Surveillance, and therefore the Notes avoid potential conflicts with SR 3.0.3 and SR 3.0.4.
| |
| SR 3.1.3.3 Verifying that the scram time for each control rod to notch position 04 is 7 seconds provides reasonable assurance that the control rod will insert when required during a DBA or transient, thereby completing its shutdown function. This SR is performed in conjunction with the control rod scram time testing of SR 3.1.4.1 and SR 3.1.4.2. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation,"
| |
| and the functional testing of SDV vent and drain valves in LCO 3.1.8, "Scram Discharge Volume (SDV) Vent and Drain Valves," overlap this Surveillance to provide complete testing of the assumed safety function. The associated Frequencies are acceptable, considering the more frequent testing performed to (continued) 120 DAEC B 3.1-21 TSCR-098
| |
| | |
| Control Rod OPERABILITY B 3.1.3 BASES SURVEILLANCE SR 3.1.3.3 (continued)
| |
| REQUIREMENTS demonstrate other aspects of control rod OPERABILITY and operating experience, which shows scram times do not significantly change over an operating cycle.
| |
| SR 3.1.3.4 Coupling verification is performed to ensure the control rod is connected to the CRDM and will perform its intended function when necessary. The Surveillance requires verifying a withdrawn control rod does not go to the withdrawn overtravel position. The overtravel position feature provides a positive check on the coupling integrity since only an uncoupled CRD can reach the overtravel position. The verification is required to be performed any time a control rod is withdrawn to the "full out" position (notch position 48) or prior to declaring the control rod OPERABLE after work on the control rod or CRD System that could affect coupling.
| |
| This includes control rods inserted one notch and then returned to the "full out" position during the performance of SR 3.1.3.2. This Frequency is acceptable, considering the low probability that a control rod will become uncoupled when it is not being moved and operating experience related to uncoupling events.
| |
| REFERENCES 1. UFSAR, Sections 3.1.2.3.7, 3.1.2.3.8, 3.1.2.3.9, and 3.1.2.3.10
| |
| : 2. UFSAR, Section 4.3.3.
| |
| : 3. UFSAR, Section 5.2.2 and Appendix 5B.
| |
| : 4. UFSAR, Section 15.0.
| |
| : 5. NEDO-21231, "Banked Position Withdrawal Sequence,"
| |
| Section 7.2, January 1977.
| |
| 120 DAEC B 3.1-22 TSCR-098
| |
| | |
| Control Rod Scram Accumulators B 3.1.5 BASES ACTIONS D.1 (continued)
| |
| The reactor mode switch must be immediately placed in the shutdown position if either Required Action and associated Completion Time associated with loss of the CRD charging pump (Required Actions B.1 and C.1) cannot be met. This ensures that all insertable control rods are inserted and that the reactor is in a condition that does not require the active function (i.e., scram) of the control rods. The insertion of a manual scram prior to placing the reactor mode switch in the Shutdown position is permitted by the definition of an Immediate Completion Time. This Required Action is modified by a Note stating that the action is not applicable if all control rods associated with the inoperable scram accumulators are fully inserted, since the function of the control rods has been performed.
| |
| SURVEILLANCE SR 3.1.5.1 REQUIREMENTS SR 3.1.5.1 requires that the accumulator pressure be checked periodically every 7 days to ensure adequate accumulator pressure exists to provide sufficient scram force. The primary indicator of accumulator OPERABILITY is the accumulator pressure. A minimum accumulator pressure is specified below which the capability of the accumulator to perform its intended function becomes degraded and the accumulator is considered inoperable.
| |
| The minimum accumulator pressure of 940 psig is well below the expected pressure of 1100 psig (Ref. 1). Declaring the accumulator inoperable when the minimum pressure is not maintained ensures that significant degradation in scram times does not occur. The 7 day Frequency has been shown to be acceptable through operating experience and takes into account indications available in the control room.
| |
| The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.1-32 Amendment 223
| |
| | |
| Rod Pattern Control B 3.1.6 BASES (continued)
| |
| SURVEILLANCE SR 3.1.6.1 periodically REQUIREMENTS The control rod pattern is verified to be in compliance with the BPWS at a 24 hour Frequency to ensure the assumptions of the CRDA analyses are met. The 24 hour Frequency was developed considering that the primary check on compliance with the BPWS The Surveillance Frequency is is performed by the RWM (LCO 3.3.2.1), which provides control controlled under the Surveillance rod blocks to enforce the required sequence and is required to be OPERABLE when operating at 10% RTP.
| |
| Frequency Control Program.
| |
| REFERENCES
| |
| : 1. NEDE-24011-P-A-US, "General Electric Standard Application for Reactor Fuel, Supplement for United States," Section 2.2.3.1.
| |
| : 2. Letter from T. A. Pickens (BWROG) to G.E. Laines (NRC),
| |
| "Amendment 17 to General Electric Licensing Topical Report NEDE-24011-P-A", BWROG-8644, August 15, 1988.
| |
| : 3. NUREG-0979, Section 4.2.1.3.2, April 1983.
| |
| : 4. NUREG-0800, Section 15.4.9, Revision 2, July 1981.
| |
| : 5. 10 CFR 50.67.
| |
| : 6. NEDO-21778-A, "Transient Pressure Rises Affected Fracture Toughness Requirements for Boiling Water Reactors," December 1978.
| |
| : 7. ASME, Boiler and Pressure Vessel Code.
| |
| : 8. NEDO-21231, "Banked Position Withdrawal Sequence,"
| |
| January 1977.
| |
| : 9. GE SIL No. 316, "Reduced Notch Worth Procedures,"
| |
| November 1979.
| |
| : 10. NEDO-33091-A, Rev.2, Improved BPWS Control Rod Insertion Process, July 2004.
| |
| 120 DAEC B 3.1-38 TSCR-093
| |
| | |
| SLC System B 3.1.7 BASES (continued)
| |
| SURVEILLANCE SR 3.1.7.1, SR 3.1.7.2, and SR 3.1.7.3 REQUIREMENTS SR 3.1.7.1 through SR 3.1.7.3 are 24 hour Surveillances verifying certain characteristics of the SLC System (e.g., the volume and temperature of the borated solution in the storage tank), thereby ensuring SLC System OPERABILITY without disturbing normal plant operation. These Surveillances ensure that the proper borated solution volume and temperature, including the temperature of the pump suction piping, are maintained.
| |
| Maintaining a minimum specified borated solution temperature is important in ensuring that the boron remains in solution and does not precipitate out in the storage tank or in the pump suction piping. The temperature versus concentration curve of Figure 3.1.7-2 ensures that a 5°F margin will be maintained above the saturation temperature. The 24 hour Frequency is based on operating experience and has shown there are relatively slow variations in the measured parameters of volume and The Surveillance Frequency is temperature.
| |
| The Surveillance Frequency is controlled under the Surveillance controlled under the Surveillance Frequency Control Program. SR 3.1.7.4 Frequency Control Program.
| |
| SR 3.1.7.4 verifies the continuity of the explosive charges in the injection valves to ensure that proper operation will occur if required. Other administrative controls, such as those that limit the shelf life of the explosive charges, must be followed. The 31 day Frequency is based on operating experience and has demonstrated the reliability of the explosive charge continuity.
| |
| SR 3.1.7.5 This Surveillance requires an examination of the sodium pentaborate solution by using chemical analysis to ensure that the proper concentration of boron exists in the storage tank.
| |
| SR 3.1.7.5 must be performed anytime boron or water is added to the storage tank solution to determine that the boron solution concentration is within the specified limits. SR 3.1.7.5 must also be performed anytime the temperature is restored to within the limits of Figure 3.1.7-2, to ensure that no significant boron precipitation occurred. The 31 day Frequency of this Surveillance is appropriate because of the relatively slow variation of boron concentration between surveillances.
| |
| The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.1-42 Amendment 223
| |
| | |
| SLC System B 3.1.7 BASES SURVEILLANCE SR 3.1.7.6 REQUIREMENTS (continued) Demonstrating that each SLC System pump develops a flow rate 26.2 gpm at a discharge pressure 1150 psig when pumping demineralized water to the test tank ensures that pump performance has not degraded below design values during the fuel cycle. This minimum pump flow rate requirement ensures that, when combined with the sodium pentaborate solution concentration requirements, the rate of negative reactivity insertion from the SLC System will adequately compensate for the positive reactivity effects encountered during power reduction, cooldown of the moderator, and xenon decay. This test confirms one point on the pump design curve and is indicative of overall performance. Such inservice inspections confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance. The Frequency of this Surveillance is in accordance with the Inservice Testing Program.
| |
| SR 3.1.7.7 and SR 3.1.7.8 These Surveillances ensure that there is a functioning flow path from the boron solution storage tank to the RPV, including the firing of an explosive valve. The replacement charge for the explosive valve shall be from the same manufactured batch as the one fired or from another batch that has been certified by having one of that batch successfully fired. The pump and explosive valve tested should be alternated such that both complete flow paths are tested every 48 months at alternating 24 month intervals. The Surveillance may be performed in separate steps to prevent injecting boron into the RPV. An acceptable method for verifying flow from the pump to the RPV is to pump demineralized water from a test tank through one SLC subsystem and into the RPV. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency; therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.1-43 Amendment 223
| |
| | |
| SLC System B 3.1.7 BASES SURVEILLANCE SR 3.1.7.7 and SR 3.1.7.8 (continued)
| |
| REQUIREMENTS Demonstrating that all heat traced piping between the boron solution storage tank and the suction inlet to the injection pumps The periodic is unblocked ensures that there is a functioning flow path for injecting the sodium pentaborate solution. Acceptable methods Surveillance for verifying that the suction piping is unblocked include pumping Frequency is from the storage tank to the test tank or establishing flow from the controlled under pump suction drains.
| |
| the Surveillance periodic Frequency The 24 month Frequency is acceptable since there is a low Control Program. probability that the subject piping will be blocked due to precipitation of the boron from solution in the heat traced piping.
| |
| This is especially true in light of the temperature verification of this piping required by SR 3.1.7.3. However, if, in performing SR 3.1.7.3, it is determined that the temperature of this piping has fallen below the specified minimum, SR 3.1.7.8 must be performed once within 24 hours after the piping temperature is restored to within the limits of Figure 3.1.7-2.
| |
| REFERENCES 1. 10 CFR 50.62.
| |
| : 2. UFSAR, Section 9.3.4.3.
| |
| : 3. NEDC-30859, "Duane Arnold ATWS Assessments" December 1984.
| |
| TSCR-120 DAEC B 3.1-44 Amendment 223
| |
| | |
| SDV Vent and Drain Valves B 3.1.8 BASES (continued)
| |
| ACTIONS C.1 (continued)
| |
| If any Required Action and associated Completion Time is not met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. The allowed Completion Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems. .
| |
| SURVEILLANCE SR 3.1.8.1 REQUIREMENTS (continued) During normal operation, the SDV vent and drain valves should be in the open position (except when performing SR 3.1.8.2) to allow for drainage of the SDV piping. Verifying that each valve is in the open position ensures that the SDV vent and drain valves will perform their intended functions during normal operation. This SR does not require any testing or valve manipulation; rather, it involves verification that the valves are in the correct position.
| |
| This SR is modified by a Note that allows the SR to be met for OPERABLE valves that are temporarily closed while performing the testing required by SR 3.1.8.2. The Note is necessary to avoid potential conflicts between the two SRs created by SR 3.0.1.
| |
| The 31 day Frequency is based on engineering judgment and is The Surveillance consistent with the procedural controls governing valve operation, Frequency is controlled which ensure correct valve positions.
| |
| under the Surveillance Frequency Control SR 3.1.8.2 Program.
| |
| During a scram, the SDV vent and drain valves should close to contain the reactor water discharged to the SDV piping. Cycling each valve through its complete range of motion (closed and open) ensures that the valve will function properly during a scram.
| |
| The Frequency is based on operating experience and takes into account the level of redundancy in the system design as well as being in accordance with the Inservice Testing Program.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.1-48 Amendment 223
| |
| | |
| SDV Vent and Drain Valves B 3.1.8 BASES SURVELLANCE SR 3.1.8.3 REQUIREMENTS SR 3.1.8.3 is an integrated test of the SDV vent and drain valves to verify total system performance. After receipt of a simulated or actual scram signal, the closure of the SDV vent and drain valves is verified. The closure time of 30 seconds after receipt of a scram signal is based on the bounding leakage case evaluated in the accident analysis (Ref. 2). Similarly, after receipt of a simulated or actual scram reset signal, the opening of the SDV vent and drain valves is verified. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.1.1 and the scram time testing of The Surveillance control rods in LCO 3.1.3 overlap this Surveillance to provide Frequency is based on complete testing of the assumed safety function. The 24 month Frequency is based on the need to perform this Surveillance operating experience, under the conditions that apply during a plant outage and the equipment reliability, and potential for an unplanned transient if the Surveillance were plant risk and is performed with the reactor at power. Operating experience has controlled under the shown these components usually pass the Surveillance when Surveillance Frequency performed at the 24 month Frequency; therefore, the Frequency Control Program. was concluded to be acceptable from a reliability standpoint.
| |
| REFERENCES 1. UFSAR, Section 4.6.2.3.
| |
| : 2. 10 CFR 50.67.
| |
| : 3. NUREG-0803, "Generic Safety Evaluation Report Regarding Integrity of BWR Scram System Piping,"
| |
| August 1981.
| |
| 120 DAEC B 3.1-49 TSCR-044A
| |
| | |
| APLHGR B 3.2.1 BASES (continued)
| |
| ACTIONS A.1 If any APLHGR exceeds the required limits, an assumption regarding an initial condition of the DBA and transient analyses may not be met. Therefore, prompt action should be taken to restore the APLHGR(s) to within the required limits such that the plant operates within analyzed conditions and within design limits of the fuel rods. The 2 hour Completion Time is sufficient to restore the APLHGR(s) to within its limits and is acceptable based on the low probability of a transient or DBA occurring simultaneously with the APLHGR out of specification.
| |
| B.1 If the APLHGR cannot be restored to within its required limits within the associated Completion Time, the plant must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, THERMAL POWER must be reduced to < 21.7% RTP within 4 hours. The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < 21.7% RTP in an orderly manner and without challenging plant systems because in general, a power reduction from full power would normally have already been initiated as part of Required Action A.1.
| |
| SURVEILLANCE SR 3.2.1.1 periodically REQUIREMENTS APLHGRs are required to be initially calculated within 12 hours after THERMAL POWER is 21.7% RTP and then every 24 hours thereafter. They are compared to the specified limits in the COLR The Surveillance Frequency is to ensure that the reactor is operating within the assumptions of controlled under the the safety analysis. The 24 hour Frequency is based on both Surveillance Frequency engineering judgment and recognition of the slowness of changes Control Program. in power distribution during normal operation. The 12 hour allowance after THERMAL POWER 21.7% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.
| |
| (continued) 120 DAEC B 3.2-4 TSCR-044
| |
| | |
| MCPR B 3.2.2 BASES (continued)
| |
| SURVEILLANCE SR 3.2.2.1 periodically REQUIREMENTS The MCPR is required to be initially calculated within 12 hours after THERMAL POWER is 21.7% RTP and then every 24 hours thereafter. It is compared to the specified limits in the COLR to The Surveillance Frequency is ensure that the reactor is operating within the assumptions of the controlled under the safety analysis. The 24 hour Frequency is based on both Surveillance Frequency engineering judgment and recognition of the slowness of changes Control Program. in power distribution during normal operation. The 12 hour allowance after THERMAL POWER 21.7% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.
| |
| SR 3.2.2.2 Because the transient analysis takes credit for conservatism in the scram speed performance, it must be demonstrated that the specific scram speed distribution is consistent with that used in the transient analysis. Therefore, in order to perform SR 3.2.2.2, the value of , which is a measure of the actual scram speed distribution compared with the assumed distribution must first be determined. The MCPR operating limit is then determined based on an interpolation between the applicable limits for Option A (scram times of LCO 3.1.4,"Control Rod Scram Times") and Option B (realistic scram times) analyses. The parameter must be determined once within 72 hours after each set of scram time tests required by SR 3.1.4.1 and SR 3.1.4.2 because the effective scram speed distribution may change after maintenance that could affect scram times. The 72 hour Completion Time is acceptable due to the large inherent margin to operating limits at low power.
| |
| REFERENCES 1. NUREG-0562, June 1979.
| |
| : 2. NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel" (latest approved version).
| |
| : 3. UFSAR, Chapters 4.2.3, 4.4.2, and 4.4.4.
| |
| : 4. UFSAR, Chapter 15.0.
| |
| : 5. Supplemental Reload Licensing Report for Duane Arnold Energy Center, (latest version referenced in COLR).
| |
| (continued) 120 DAEC B 3.2-10 TSCR-044A
| |
| | |
| RPS Instrumentation B 3.3.1.1 BASES (continued)
| |
| SURVEILLANCE As noted at the beginning of the SRs, the SRs for each RPS REQUIREMENTS instrumentation Function are located in the SRs column of Table 3.3.1.1-1.
| |
| The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours, provided the associated Function maintains RPS trip capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken.
| |
| This Note is based on the reliability analysis (Ref. 9) assumption of the average time required to perform channel Surveillance.
| |
| That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the RPS will trip when necessary.
| |
| SR 3.3.1.1.1 Performance of the CHANNEL CHECK once every 12 hours ensures that a gross failure of instrumentation has not occurred.
| |
| A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.
| |
| Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it The Surveillance Frequency is may be an indication that the instrument has drifted outside its controlled under the limit.
| |
| Surveillance Frequency Control Program. The Frequency is based upon operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels (continued)
| |
| TSCR-120 DAEC B 3.3-26 Amendment 223
| |
| | |
| RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.1 (continued)
| |
| REQUIREMENTS during normal operational use of the displays associated with the channels required by the LCO.
| |
| SR 3.3.1.1.2 To ensure that the APRMs are accurately indicating the true core average power, the APRMs are calibrated to the reactor power calculated from a heat balance. LCO 3.4.1, "Recirculation Loops Operating," allows the APRMs to be reading greater than actual THERMAL POWER to effectively lower the APRM Flow Biased High setpoints by 6.3% for single recirculation loop operation.
| |
| When this adjustment is made, the requirement for the APRMs to indicate within 2% RTP of calculated power is modified to require The Surveillance Frequency is the APRMs to indicate within 2% RTP of calculated power plus controlled under the 6.3%. The Frequency of once per 24 hours is based on minor Surveillance Frequency changes in LPRM sensitivity, which could affect the APRM Control Program. reading between performances of SR 3.3.1.1.8. Frequency A restriction to satisfying this SR when < 21.7% RTP is provided that requires the SR to be met only at 21.7% RTP because it is difficult to accurately maintain APRM indication of core THERMAL POWER consistent with a heat balance when < 21.7% RTP. At low power levels, a high degree of accuracy is unnecessary because of the large, inherent margin to thermal limits (MCPR and APLHGR). At 21.7% RTP, the Surveillance is required to have been satisfactorily performed within the previous 24 hours, in accordance with SR 3.0.2. A Note is provided which allows an increase in THERMAL POWER above 21.7% if the 24 hour Frequency is not met per SR 3.0.2. In this event, the SR must be performed within 12 hours after reaching or exceeding 21.7%
| |
| RTP. Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.
| |
| SR 3.3.1.1.3 The surveillance frequency extensions for various RPS functions are permitted by Reference 9, provided the automatic scram contactors are functionally tested weekly. There are four pairs of RPS automatic scram contactors (i.e., K14 relay contacts) with each pair associated with an automatic scram logic (A1, A2, B1, and B2). The automatic scram contactors can be functionally tested without the necessity of using an automatic scram (continued) 120 DAEC B 3.3-27 TSCR-044A
| |
| | |
| RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.3 (continued)
| |
| REQUIREMENTS function trip. This functional test can be accomplished by placing the associated RPS Test Switch in the trip position, which will deenergize a pair of the automatic scram contactors and in turn, trip the associated RPS logic. The RPS Test Switches were not specifically credited in the accident analysis and thus, do not have any OPERABILITY requirements of their own. However, because the Manual Scram pushbuttons at the DAEC are not configured the same as the generic model used in Reference 9, (i.e., they are in a separate RPS logic - A3 and B3), the RPS Test Switches have been found to be functionally equivalent to the Manual Scram pushbuttons in the generic model for performing the weekly functional test of the automatic scram contactors required by Reference 9. If an RPS Test Switch(es) is (are) not available for performing this test, it is permissible to take credit for a CHANNEL FUNCTIONAL TEST of an automatic RPS trip function The Surveillance Frequency is (i.e., SR 3.3.1.1.9), if performed within the required Frequency for controlled under the this Surveillance, as it will also test the K14 relay contacts.
| |
| Surveillance Frequency Control Program. The Frequency of 7 days is based upon the reliability analysis in Reference 9.
| |
| SR 3.3.1.1.4 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.
| |
| As noted, SR 3.3.1.1.4 is not required to be performed when entering MODE 2 from MODE 1, since testing of the MODE 2 required IRM and APRM Functions cannot be performed in MODE 1 without utilizing jumpers, lifted leads, or movable links.
| |
| (continued) 120 DAEC B 3.3-28 TSCR-026A
| |
| | |
| RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.4 (continued)
| |
| REQUIREMENTS This allows entry into MODE 2 if the 7 day Frequency is not met per SR 3.0.2. In this event, the SR must be performed within 12 hours after entering MODE 2 from MODE 1. Twelve hours is The Surveillance Frequency is based on operating experience and in consideration of providing a controlled under the reasonable time in which to complete the SR. A Frequency of Surveillance Frequency 7 days provides an acceptable level of system average Control Program. The unavailability over the Frequency interval and is based on reliability analysis (Ref. 9).
| |
| SR 3.3.1.1.5 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical The Surveillance Frequency is Specifications tests at least once per refueling interval with controlled under the applicable extensions. A Frequency of 7 days provides an Surveillance Frequency acceptable level of system average availability over the Control Program. The Frequency and is based on the reliability analysis using the concepts developed in Reference 10.
| |
| s 9 and SR 3.3.1.1.6 and SR 3.3.1.1.7 These Surveillances are established to ensure that no gaps in neutron flux indication exist from subcritical to power operation for monitoring core reactivity status.
| |
| The overlap between SRMs and IRMs is required to be demonstrated to ensure that reactor power will not be increased into a neutron flux region without adequate indication. This is required prior to withdrawing SRMs from the fully inserted position since indication is being transitioned from the SRMs to the IRMs.
| |
| The overlap between IRMs and APRMs is of concern when reducing power into the IRM range. On power increases, the system design will prevent further increases (by initiating a rod block) if adequate overlap is not maintained.
| |
| (continued) 120 DAEC B 3.3-29 TSCR-026A
| |
| | |
| RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.6 and SR 3.3.1.1.7 (continued)
| |
| REQUIREMENTS Overlap between IRMs and APRMs exists when sufficient IRMs and APRMs concurrently have onscale readings such that the transition between MODE 1 and MODE 2 can be made without either APRM downscale rod block, or IRM upscale rod block (i.e.,
| |
| approximately one-half decade of range). Overlap between SRMs and IRMs similarly exists when, prior to withdrawing the SRMs from the fully inserted position, IRMs are indicating at least 5/40 on range 1 before SRMs have reached 106 counts per second.
| |
| As noted, SR 3.3.1.1.7 is only required to be met during entry into MODE 2 from MODE 1. That is, after the overlap requirement has been met and indication has transitioned to the IRMs, maintaining overlap is not required (APRMs may be reading downscale once in MODE 2).
| |
| The Surveillance If overlap for a group of channels is not demonstrated (e.g.,
| |
| Frequency is controlled IRM/APRM overlap), the reason for the failure of the Surveillance under the Surveillance should be determined and the appropriate channel(s) declared inoperable. Only those appropriate channels that are required in Frequency Control the current MODE or condition should be declared inoperable.
| |
| Program. The A Frequency of 7 days is reasonable based on engineering judgment and the reliability of the IRMs and APRMs.
| |
| SR 3.3.1.1.8 The Surveillance LPRM gain settings are determined using analytical methods with Frequency is controlled input from the axial flux profiles measured by the Traversing under the Surveillance Incore Probe (TIP) System. This establishes the relative local flux Frequency Control profile for appropriate representative input to the APRM System.
| |
| Program. The 1000 MWD/T Frequency is based on operating experience with LPRM sensitivity changes.
| |
| SR 3.3.1.1.9 and SR 3.3.1.1.13 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verificiation of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay (continued) 120 DAEC B 3.3-30 TSCR-026A
| |
| | |
| RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.9 and SR 3.3.1.1.13 (continued)
| |
| REQUIREMENTS are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. The 92 day Frequency of SR 3.3.1.1.9 is based on the reliability analysis of Reference 9.
| |
| The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency.
| |
| 9 SR 3.3.1.1.10 Calibration of trip units provides a check of the actual trip setpoints. The channel must be declared inoperable if the trip setting is discovered to be less conservative than the Allowable Value specified in Table 3.3.1.1-1. If the trip setting is discovered to be less conservative than accounted for in the appropriate setpoint methodology, but is not beyond the Allowable Value, the channel performance is still within the requirements of the plant The Surveillance safety analysis. Under these conditions, the setpoint must be Frequency is readjusted to be equal to or more conservative than accounted for controlled under in the appropriate setpoint methodology. The Frequency of the Surveillance 92 days is based on the reliability analysis of Reference 9.
| |
| Frequency Control 10 11 Program. SR 3.3.1.1.11, SR 3.3.1.1.12 and SR 3.3.1.1.14 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies that the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology. The CHANNEL CALIBRATION for Functions 5 and 8 shall consist of the physical inspection and actuation of these position switches.
| |
| (continued) 120 DAEC B 3.3-31 TSCR-026A
| |
| | |
| RPS Instrumentation B 3.3.1.1 BASES 10 11 SURVEILLANCE SR 3.3.1.1.11, SR 3.3.1.1.12 and SR 3.3.1.1.14 (continued)
| |
| REQUIREMENTS Note 1 states that neutron detectors are excluded from CHANNEL CALIBRATION because they are passive devices, with minimal drift, and because of the difficulty of simulating a meaningful signal. Changes in neutron detector sensitivity are compensated for by performing the calorimetric calibration (SR 3.3.1.1.2) every 24 hours and the 1000 MWD/T LPRM calibration against the TIPs (SR 3.3.1.1.8). A second Note is provided that requires the APRM and IRM SRs to be performed within 12 hours of entering MODE 2 from MODE 1. Testing of the MODE 2 APRM and IRM Functions cannot be performed in MODE 1 without utilizing jumpers, lifted leads, or movable links. This Note allows entry into The Surveillance MODE 2 from MODE 1 if the associated Frequency is not met per Frequency is controlled SR 3.0.2. Twelve hours is based on operating experience and in under the Surveillance consideration of providing a reasonable time in which to complete the SR.
| |
| Frequency Control Program. The Frequency of SR 3.3.1.1.11 is based upon the assumption of a 92 day calibration interval in the determination of the magnitude specified of equipment drift in the setpoint analysis. The Frequency of SR 3.3.1.1.12 is based upon the assumption of a 184 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis. The Frequency of SR 3.3.1.1.14 is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
| |
| 12 SR 3.3.1.1.15 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the The Surveillance OPERABILITY of the required trip logic for a specific channel.
| |
| Frequency is controlled The functional testing of control rods (LCO 3.1.3), and SDV vent under the Surveillance and drain valves (LCO 3.1.8), overlaps this Surveillance to provide complete testing of the assumed safety function.
| |
| Frequency Control Program. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency.
| |
| this (continued)
| |
| TSCR-120 DAEC B 3.3-32 Amendment 223
| |
| | |
| RPS Instrumentation B 3.3.1.1 BASES 13 SURVEILLANCE SR 3.3.1.1.16 REQUIREMENTS (continued) This SR ensures that scrams initiated from the Turbine Stop Valve Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure Low Functions will not be inadvertently bypassed when THERMAL POWER is 26% RTP. This involves calibration of the bypass channels. Adequate margins for the instrument setpoint methodologies are incorporated into the actual setpoint.
| |
| Because main turbine bypass flow, as well as other turbine steam loads, can affect this setpoint nonconservatively (THERMAL POWER is derived from turbine first stage pressure), the main turbine bypass valves must remain closed at THERMAL POWER 26% RTP to ensure that the calibration remains valid. If any bypass channel's setpoint is nonconservative (i.e., the Functions are bypassed at 26% RTP, either due to open main turbine bypass valve(s) (e.g., required testing or upon actual demand) or other reasons, such as changes in turbine steamload to the Main Steam Reheaters), then the affected Turbine Stop Valve Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure Low Functions are considered inoperable. Alternatively, the The Surveillance bypass channel can be placed in the conservative condition Frequency is controlled (nonbypass). If placed in the nonbypass condition, this SR is met under the Surveillance and the channel is considered OPERABLE.
| |
| Frequency Control Program. The Frequency of 24 months is based on engineering judgment and reliability of the components.
| |
| 14 SR 3.3.1.1.17 The Average Power Range Monitor Flow Biased High Function uses the recirculation loop drive flows to vary the trip setpoint.
| |
| This SR ensures that the total loop drive flow signals from the flow units used to vary the setpoint is appropriately compared to a calibrated flow signal and, therefore, the APRM Function accurately reflects the required setpoint as a function of flow.
| |
| Each flow signal from the respective flow unit must be 110% of the calibrated flow signal. If the flow unit signal is not within the limit, that flow unit may be bypassed, and its output to the low auction circuit will be maximum, making the low auction circuit select the input from the operating flow unit.
| |
| (continued) 120 DAEC B 3.3-33 TSCR-123
| |
| | |
| RPS Instrumentation B 3.3.1.1 BASES 14 SURVEILLANCE SR 3.3.1.1.17 (continued)
| |
| REQUIREMENTS The Frequency of 24 months is based on engineering judgment, The Surveillance operating experience, the reliability of this instrumentation, the Frequency is controlled other surveillances performed on the components of the flow under the Surveillance biasing network, and the fact that a half scram will be present for Frequency Control an extended period of time during the performance of this Program. surveillance.
| |
| 15 SR 3.3.1.1.18 This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis. The RPS Response Time test only applies to the Functions of Reactor Vessel Water Level - Low and Reactor Vessel Steam Dome Pressure - High. These RPS Functions are the only ones that were identified, in a program conducted prior to The Surveillance the first refueling outage, that require sensor response time testing. This test may be performed in one measurement or in Frequency is overlapping segments, with verification that all components are controlled under tested. The RPS RESPONSE TIME acceptance criteria are the Surveillance included in Reference 13.
| |
| Frequency Control Program. RPS RESPONSE TIME tests are conducted on a 24 month STAGGERED TEST BASIS. This Frequency is based on the logic interrelationships of the various channels required to produce an RPS scram signal. The 24 month Frequency is consistent with the typical industry refueling cycle and is based upon plant operating experience, which shows that random failures of instrumentation components causing serious response time degradation, but not channel failure, are infrequent occurrences.
| |
| 16 SR 3.3.1.1.19 This SR ensures that the RPS logic system response times are less than or equal to the maximum value assumed in the accident analysis. The RPS logic system response time test is measured from the opening of the sensor contact up to and including the opening of the trip actuator contacts. As such, this test does not include the sensor response time. All RPS Functions except the RPS Manual Scram and Reactor Mode Switch - Shutdown Position are included in this test.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.3-34 Amendment 223
| |
| | |
| RPS Instrumentation B 3.3.1.1 BASES 16 SURVEILLANCE SR 3.3.1.1.19 (continued)
| |
| REQUIREMENTS The Surveillance These two RPS Functions are excluded since they directly trip Frequency is their scram solenoid relays without any intervening devices, thus there is nothing to response time test. This test may be controlled under performed in one measurement or in overlapping segments, with the Surveillance verification that all components are tested. The RPS logic system Frequency Control response time acceptance criteria are included in Reference 13.
| |
| Program. RPS logic system response time tests are conducted on a 24 month STAGGERED TEST BASIS. This Frequency is based on the logic interrelationships of the various channels required to produce an RPS scram signal. The 24 month Frequency is consistent with the typical industry refueling cycle and is based upon plant operating experience, which shows that random failures of instrumentation components causing serious response time degradation, but not channel failure, are infrequent occurrences.
| |
| REFERENCES 1. UFSAR, Figure 7.2-2.
| |
| : 2. UFSAR, Section 15.1.4.2.
| |
| : 3. NEDO-23842, "Continuous Control Rod Withdrawal in the Startup Range," April 18, 1978.
| |
| : 4. UFSAR, Section 5.2.2 and Appendix 5B.
| |
| : 5. UFSAR, Section 15.2.4.
| |
| : 6. UFSAR, Section 15.2.1.
| |
| : 7. UFSAR, Chapter 15.1.
| |
| : 8. P. Check (NRC) letter to G. Lainas (NRC), "BWR Scram Discharge System Safety Evaluation," December 1, 1980.
| |
| : 9. NEDO-30851-P-A , "Technical Specification Improvement Analyses for BWR Reactor Protection System,"
| |
| March 1988.
| |
| : 10. Reliability of Engineered Safety Features as a Function of Testing Frequency, Volume 9, No. 4, July-August 1968.
| |
| (continued) 120 DAEC B 3.3-35 TSCR-044A
| |
| | |
| SRM Instrumentation B 3.3.1.2 BASES SURVEILLANCE SR 3.3.1.2.1 and SR 3.3.1.2.3 REQUIREMENTS (continued) Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on another channel. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.
| |
| Agreement criteria are determined by the plant staff based on a The Surveillance combination of the channel instrument uncertainties, including Frequency is controlled indication and readability. If a channel is outside the criteria, it under the Surveillance may be an indication that the instrument has drifted outside its Frequency Control limit.
| |
| Program.
| |
| The Frequency of once every 12 hours for SR 3.3.1.2.1 is based on operating experience that demonstrates channel failure is rare.
| |
| While in MODES 3 and 4, reactivity changes are not expected; therefore, the 12 hour Frequency is relaxed to 24 hours for from MODES 2 and 5 SR 3.3.1.2.3. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.
| |
| SR 3.3.1.2.2 To provide adequate coverage of potential reactivity changes in the core when the fueled region encompasses more than one SRM, one SRM is required to be OPERABLE in the quadrant where CORE ALTERATIONS are being performed, and the other OPERABLE SRM must be in an adjacent quadrant containing fuel. Note 1 states that the SR is required to be met only during CORE ALTERATIONS. It is not required to be met at other times in MODE 5 since core reactivity changes are not occurring. This Surveillance consists of a review of plant logs to ensure that SRMs required to be OPERABLE for given CORE ALTERATIONS are, in fact, OPERABLE. In the event that only one SRM is required to be OPERABLE, per Table 3.3.1.2-1, footnote (b),
| |
| (continued)
| |
| TSCR-120 DAEC B 3.3-42 Amendment 223
| |
| | |
| SRM Instrumentation B 3.3.1.2 BASES SURVEILLANCE SR 3.3.1.2.2 (continued)
| |
| REQUIREMENTS The Surveillance only the a. portion of this SR is required. Note 2 clarifies that Frequency is controlled more than one of the three requirements can be met by the same under the Surveillance OPERABLE SRM. The 12 hour Frequency is based upon operating experience and supplements operational controls over Frequency Control refueling activities that include steps to ensure that the SRMs Program. required by the LCO are in the proper quadrant.
| |
| 3 SR 3.3.1.2.4 This Surveillance consists of a verification of the SRM instrument readout to ensure that the SRM reading is greater than a specified minimum count rate with the detector fully inserted into the core.
| |
| The requirement of at least 3 cps assures that any transient, should it occur, begins at or above the initial value of 10-8 of RTP which is used in the analysis of transients in cold conditions. With few fuel assemblies loaded, the SRMs may not have a high enough count rate to satisfy the SR. Therefore, allowances are made for loading sufficient "source" material, in the form of irradiated fuel assemblies, to establish the minimum count rate.
| |
| To accomplish this, the SR is modified by a Note that states that the count rate is not required to be met on an SRM that has less The Surveillance than or equal to four fuel assemblies adjacent to the SRM and no Frequency is controlled other fuel assemblies are in the associated core quadrant. With under the Surveillance four or less fuel assemblies loaded around each SRM and no other fuel assemblies in the associated core quadrant, even with a Frequency Control control rod withdrawn, the configuration will not be critical.
| |
| Program.
| |
| The Frequency is based upon channel redundancy and other information available in the control room, and ensures that the required channels are frequently monitored while core reactivity changes are occurring. When no reactivity changes are in during CORE progress, the Frequency is relaxed from 12 hours to 24 hours.
| |
| ALTERATIONS that during CORE ALTERATIONS (continued)
| |
| TSCR-120 DAEC B 3.3-43 Amendment 223
| |
| | |
| SRM Instrumentation B 3.3.1.2 BASES 4 5 SURVEILLANCE SR 3.3.1.2.5 and SR 3.3.1.2.6 REQUIREMENTS (continued) Performance of a CHANNEL FUNCTIONAL TEST demonstrates the associated channel will function properly. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at The Surveillance least once per refueling interval with applicable extensions.
| |
| Frequency is 4 SR 3.3.1.2.5 is required in MODE 5, and the 7 day Frequency ensures that the channels are OPERABLE while core reactivity controlled under changes could be in progress. This Frequency is reasonable, the Surveillance based on operating experience and on other Surveillances (such Frequency as a CHANNEL CHECK), that ensure proper functioning between Control Program. CHANNEL FUNCTIONAL TESTS.
| |
| The 5 SR 3.3.1.2.6 is required in MODE 2 with IRMs on Range 2 or The Surveillance below, and in MODES 3 and 4. Since core reactivity changes do not normally take place in MODES 3 and 4 and core reactivity Frequency is changes are due solely to control rod movement in MODE 2, the that in controlled under Frequency has been extended from 7 days to 31 days. The MODE 5
| |
| the Surveillance 31 day Frequency is based on operating experience and on other Frequency Surveillances (such as CHANNEL CHECK) that ensure proper Control Program. functioning between CHANNEL FUNCTIONAL TESTS.
| |
| The Note to the Surveillance allows the Surveillance to be delayed until entry into the specified condition of the Applicability (THERMAL POWER decreased to IRM Range 2 or below). The Surveillance SR must be performed within 12 hours after IRMs are on Range 2 or below. The allowance to enter the Applicability with the 31 day Frequency not met is reasonable, based on the limited time of 12 hours allowed after entering the Applicability and the inability to perform the Surveillance while at higher power levels. Although the Surveillance could be performed while on IRM Range 3, the plant would not be expected to maintain steady state operation at this power level. In this event, the 12 hour Frequency is reasonable, based on the SRMs being otherwise verified to be OPERABLE (i.e., satisfactorily performing the CHANNEL CHECK) and the time required to perform the Surveillances.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.3-44 TSCR-026A
| |
| | |
| SRM Instrumentation B 3.3.1.2 BASES 6
| |
| SURVEILLANCE SR 3.3.1.2.7 REQUIREMENTS (continued) Performance of a CHANNEL CALIBRATION at a Frequency of The Surveillance Frequency 24 months verifies the performance of the SRM detectors and is controlled under the associated circuitry. The Frequency considers the plant Surveillance Frequency conditions required to perform the test, the ease of performing the Control Program. test, and the likelihood of a change in the system or component status. Note 1 to the Surveillance allows the neutron detectors to be excluded from the CHANNEL CALIBRATION because they cannot readily be adjusted. The detectors are fission chambers that are designed to have a relatively constant sensitivity over the range and with an accuracy specified for a fixed useful life.
| |
| Note 2 to the Surveillance allows the Surveillance to be delayed until entry into the specified condition of the Applicability. The SR must be performed in MODE 2 within 12 hours of entering MODE 2 with IRMs on Range 2 or below. The allowance to enter the Surveillance Applicability with the 24 month Frequency not met is reasonable, based on the limited time of 12 hours allowed after entering the Applicability and the inability to perform the Surveillance while at higher power levels. Although the Surveillance could be performed while on IRM Range 3, the plant would not be expected to maintain steady state operation at this power level. In this event, the 12 hour Frequency is reasonable, based on the SRMs being otherwise verified to be OPERABLE (i.e., satisfactorily performing the CHANNEL CHECK) and the time required to perform the Surveillances.
| |
| REFERENCES None.
| |
| TSCR-120 DAEC B 3.3-45 Amendment 223
| |
| | |
| Control Rod Block Instrumentation B 3.3.2.1 BASES (continued)
| |
| SURVEILLANCE SR 3.3.2.1.1 REQUIREMENTS A CHANNEL FUNCTIONAL TEST is performed for each RBM channel to ensure that the entire channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. It includes the Reactor Manual Control Multiplexing System input.
| |
| The Surveillance Testing of the Reactor Manual Control Multiplexing System input Frequency is shall include inputs of "no rod selected," "peripheral rod selected,"
| |
| controlled under and "center rod selected with two, three, or four LPRM strings the Surveillance around it" (Ref. 10).
| |
| Frequency The Frequency of 92 days is based on reliability analyses (Ref. 8).
| |
| Control Program.
| |
| SR 3.3.2.1.2 and SR 3.3.2.1.3 A CHANNEL FUNCTIONAL TEST is performed for the RWM to ensure that the entire system will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. The CHANNEL FUNCTIONAL TEST for the RWM is performed by attempting to withdraw a control rod not in compliance with the prescribed sequence and verifying a control rod block occurs and for SR 3.3.2.1.2, and by attempting to select a control rod, in each fully inserted group, not in compliance with the prescribed sequence and verifying a selection error occurs. As noted in the SRs, SR 3.3.2.1.2 is not required to be performed until 1 hour after any control rod is withdrawn at 10% RTP in MODE 2, and SR 3.3.2.1.3 is not required to be performed until 1 hour after THERMAL POWER is 10% RTP in (continued) 120 DAEC B 3.3-54 TSCR-070
| |
| | |
| Control Rod Block Instrumentation B 3.3.2.1 BASES (continued)
| |
| SURVEILLANCE SR 3.3.2.1.2 and SR 3.3.2.1.3 (continued) Surveillance REQUIREMENTS MODE 1. This allows entry into MODE 2 for SR 3.3.2.1.2, and entry into MODE 1 when THERMAL POWER is 10% RTP for The Surveillance SR 3.3.2.1.3, to perform the required Surveillance if the 92 day Frequency is Frequency is not met per SR 3.0.2. The 1 hour allowance is controlled under based on operating experience and in consideration of providing a the Surveillance reasonable time in which to complete the SRs. The Frequencies are based on reliability analysis (Ref. 8).
| |
| Frequency Control Program.
| |
| SR 3.3.2.1.4 The RBM setpoints are automatically varied as a function of power. Three Allowable Values are specified in Table 3.3.2.1-1, each within a specific power range. The power at which the control rod block Allowable Values, which are verified during the CHANNEL CALIBRATION, automatically change are based on the APRM signal's input to each RBM channel. Below the minimum power setpoint, the RBM is automatically bypassed.
| |
| These power Allowable Values must be verified periodically to be within the specified ranges to ensure that the Analytical Limits for the ranges specified in Table 3.3.2.1-1 are met. If any power range setpoint is nonconservative, then the affected RBM channel is considered inoperable. Alternatively, the power range channel can be placed in the conservative condition (i.e., enabling the proper RBM setpoint). If placed in this condition, the SR is met and the RBM channel is not considered inoperable. As noted, The Surveillance neutron detectors are excluded from the Surveillance because Frequency is they are passive devices, with minimal drift, and because of the controlled under difficulty of simulating a meaningful signal. Neutron detectors are the Surveillance adequately tested in SR 3.3.1.1.2 and SR 3.3.1.1.8. The 184 day Frequency is based on the actual trip setpoint methodology Frequency utilized for these channels.
| |
| Control Program.
| |
| SR 3.3.2.1.5 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy.
| |
| (continued) 120 DAEC B 3.3-55 TSCR-070
| |
| | |
| Control Rod Block Instrumentation B 3.3.2.1 BASES (continued)
| |
| SURVEILLANCE SR 3.3.2.1.5 (continued)
| |
| REQUIREMENTS CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the DAEC Instrument Setpoint Methodology.
| |
| As noted, neutron detectors are excluded from the CHANNEL CALIBRATION because they are passive devices, with minimal The Surveillance drift, and because of the difficulty of simulating a meaningful Frequency is signal. Neutron detectors are adequately tested in SR 3.3.1.1.2 controlled under and SR 3.3.1.1.8.
| |
| the Surveillance Frequency The Frequency is based upon the assumption of a 184 day Control Program. calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
| |
| SR 3.3.2.1.6 A CHANNEL FUNCTIONAL TEST is performed for the Reactor Mode Switch Shutdown Position Function to ensure that the entire channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay.
| |
| This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. The CHANNEL FUNCTIONAL TEST for the Reactor Mode Switch Shutdown Position Function is performed by attempting to withdraw any control rod with the reactor mode switch in the shutdown position and verifying a control rod block occurs. As noted in the SR, the Surveillance is not required to be performed until 1 hour after the reactor mode switch is in the shutdown position, since testing of this interlock with the reactor mode switch in any other position cannot be performed without using jumpers, lifted leads, or movable links. This allows entry into Surveillance MODES 3 and 4 if the 24 month Frequency is not met per SR 3.0.2. The 1 hour allowance is based on operating experience and in consideration of providing a reasonable time in which to complete the SRs.
| |
| (continued) 120 DAEC B 3.3-56 TSCR-070
| |
| | |
| Control Rod Block Instrumentation B 3.3.2.1 BASES (continued)
| |
| SURVEILLANCE SR 3.3.2.1.6 (continued)
| |
| REQUIREMENTS The 24 month Frequency is based on the need to perform this The Surveillance Surveillance under the conditions that apply during a plant Frequency is outage and the potential for an unplanned transient if the controlled under Surveillance were performed with the reactor at power. Operating the Surveillance experience has shown these components usually pass the Frequency Surveillance when performed at the 24 month Frequency.
| |
| Control Program. on this SR 3.3.2.1.7 The RWM will only enforce the proper control rod sequence if the rod sequences are properly input into the RWM computer.
| |
| This SR ensures that the proper sequences are loaded into the RWM so that it can perform its intended function. The Surveillance is performed once prior to declaring the RWM OPERABLE following loading of a sequence into the RWM, since this is when rod sequence input errors are possible.
| |
| (continued) 120 DAEC B 3.3-57 TSCR-070
| |
| | |
| PAM Instrumentation B 3.3.3.1 BASES (continued)
| |
| SURVEILLANCE The following SRs apply to the PAM instrumentation Functions in REQUIREMENTS Table 3.3.3.1-1, except as noted.
| |
| SR 3.3.3.1.1 Performance of the CHANNEL CHECK once every 31 days ensures that a gross failure of instrumentation has not occurred.
| |
| A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel against a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION. The HPCI and RCIC steam line instrumentation of the reactor steam dome pressure Function are compared to each other to satisfy this SR. For PCIV position indication, the CHANNEL CHECK consists of a comparison of the open and closed position lights with the expected position of the PCIV.
| |
| Agreement criteria are determined by the plant staff, based on a The Surveillance combination of the channel instrument uncertainties, including Frequency is isolation, indication, and readability. If a channel is outside the criteria, it may be an indication that the sensor or the signal controlled under processing equipment has drifted outside its limit. The Frequency the Surveillance of 31 days is based upon plant operating experience, with regard Frequency to channel OPERABILITY and drift, which demonstrates that Control Program. failure of more than one channel of a given Function in any 31 day interval is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of those displays associated with the required channels of this LCO.
| |
| this (continued) 120 DAEC B 3.3-68 TSCR-067A
| |
| | |
| PAM Instrumentation B 3.3.3.1 BASES SURVEILLANCE SR 3.3.3.1.2 REQUIREMENTS (continued)
| |
| A CHANNEL CALIBRATION is performed every 24 months, or approximately at every refueling. CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies the channel responds to the measured parameter with the necessary range and accuracy. For PCIV position indication, the CHANNEL CALIBRATION is a comparison of a local visual check to remote control room indication to verify the PCIV's indicated position agrees with the actual position. If an indication does not agree with the actual position, adjustments are made to the PCIV's indication channel. For Primary Containment Area Radiation instrumentation (Drywell and Suppression Chamber),
| |
| The Surveillance the CHANNEL CALIBRATION shall consist of an electronic Frequency is calibration of the channel for ranges above 10 R/hr and a one controlled under point calibration check of the detector below 10 R/hr with a the Surveillance portable gamma source.
| |
| Frequency Control Program. The Frequency is based on operating experience and consistency with the typical industry refueling cycles.
| |
| REFERENCES 1. Regulatory Guide 1.97, Revision 2, "Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident," December 1980.
| |
| : 2. R. M. Pulsifer (NRC) to L. Liu (IELP), "Duane Arnold Energy Center - Conformance to Regulatory Guide 1.97, Revision 2 (TAC M84788)," dated August 4, 1993.
| |
| : 3. DAEC License Amendment 254, transmitted by letter, D.
| |
| Beaulieu (USNRC) to M. Peifer (NMC), Duane Arnold Energy Center - Issuance ofAmendment Re: Relocation of Requirements for Hydrogen and Oxygen Monitors, dated June 10, 2004.
| |
| (continued) 120 DAEC B 3.3-68 TSCR-067A
| |
| | |
| Remote Shutdown System B 3.3.3.2 BASES ACTIONS As such, a Note has been provided that allows separate Condition (continued) entry for each inoperable Remote Shutdown System Function.
| |
| A.1 Condition A addresses the situation where one or more required Functions of the Remote Shutdown System is inoperable. This includes any instrument channel Function listed in Table B 3.3.3.2-1, as well as the transfer/control circuit Functions.
| |
| The Required Action is to restore the Function to OPERABLE status within 30 days. The Completion Time is based on operating experience and the low probability of an event that would require evacuation of the control room.
| |
| B.1 If the Required Action and associated Completion Time of Condition A are not met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. The allowed Completion Time is reasonable, based on operating experience, to reach the required MODE from full power conditions in an orderly manner and without challenging plant systems.
| |
| SURVEILLANCE SR 3.3.3.2.1 REQUIREMENTS SR 3.3.3.2.1 verifies each required Remote Shutdown System transfer switch and control circuit performs the intended function.
| |
| This verification is performed from the remote shutdown panel and locally, as appropriate. Operation of the equipment from the remote shutdown panel is not necessary. The Surveillance can The Surveillance be satisfied by performance of a continuity check. This will ensure Frequency is that if the control room becomes inaccessible, the plant can be controlled under placed and maintained in MODE 3 from the remote shutdown panel and the local control stations. Operating experience the Surveillance demonstrates that Remote Shutdown System control channels Frequency usually pass the Surveillance when performed at the 24 month this Control Program. Frequency.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.3-73 Amendment 223
| |
| | |
| Remote Shutdown System B 3.3.3.2 BASES SURVEILLANCE SR 3.3.3.2.2 REQUIREMENTS (continued) CHANNEL CALIBRATION is a complete check of the instrument The Surveillance loop and the sensor for each of the instrument channel functions.
| |
| Frequency is The test verifies the channel responds to measured parameter controlled under the values with the necessary range and accuracy.
| |
| Surveillance Frequency Control The 24 month Frequency is based upon operating experience and Program. consistency with the typical industry refueling cycle.
| |
| REFERENCES 1. UFSAR, Section 7.4.2.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.3-74 Amendment 223
| |
| | |
| EOC-RPT Instrumentation B 3.3.4.1 BASES ACTIONS C.1 and C.2 (continued)
| |
| With any Required Action and associated Completion Time not met, THERMAL POWER must be reduced to < 26% RTP within 4 hours. Alternately, the associated recirculation pump may be removed from service, since this performs the intended function of the instrumentation. The allowed Completion Time of 4 hours is reasonable, based on operating experience, to reduce THERMAL POWER to < 26% RTP from full power conditions in an orderly manner and without challenging plant systems.
| |
| SURVEILLANCE The Surveillances are modified by a Note to indicate that when a REQUIREMENTS channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains EOC-RPT trip capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken.
| |
| This Note is based on the reliability analysis (Ref. 4) assumption of the average time required to perform channel Surveillance.
| |
| That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the recirculation pumps will trip when necessary.
| |
| SR 3.3.4.1.1 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay The Surveillance are verified by other Technical Specifications and non-Technical Frequency is Specifications tests at least once per refueling interval with applicable extensions. The RPT breaker is excluded from this controlled under testing.
| |
| the Surveillance Frequency The Frequency of 92 days is based on reliability analysis of Control Program. Reference 4.
| |
| (continued) 120 DAEC B 3.3-84 TSCR-044
| |
| | |
| EOC-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE SR 3.3.4.1.2 REQUIREMENTS (continued) CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.
| |
| The Surveillance Frequency is The Frequency is based upon the assumption of a 24 month controlled under calibration interval in the determination of the magnitude of the Surveillance equipment drift in the setpoint analysis.
| |
| Frequency Control Program. SR 3.3.4.1.3 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel.
| |
| The functional test of the pump breakers is included as a part of this test, overlapping the LOGIC System Functional Test, to provide complete testing of the associated safety function.
| |
| Therefore, if a breaker is incapable of operating, the associated instrument channel(s) would also be inoperable.
| |
| The Surveillance Frequency is The 24 month Frequency is based on the need to perform this controlled under Surveillance under the conditions that apply during a plant outage the Surveillance and the potential for an unplanned transient if the Surveillance Frequency were performed with the reactor at power. Operating experience Control Program. has shown these components usually pass the Surveillance when performed at the 24 month Frequency.
| |
| this SR 3.3.4.1.4 This SR ensures that an EOC-RPT initiated from the TSV Closure and TCV Fast Closure, Trip Oil Pressure Low Functions will not be inadvertently bypassed when THERMAL POWER is 26% RTP. This involves calibration of the bypass channels. The 26% RTP is the analytical limit. Adequate margins for the instrument setpoint methodologies are incorporated into the actual setpoint. Because main turbine bypass flow can affect this setpoint nonconservatively (THERMAL POWER is derived from turbine first stage pressure) the main turbine bypass valves must remain closed whenever THERMAL POWER 26% RTP to ensure (continued) 120 DAEC B 3.3-85 TSCR-123
| |
| | |
| EOC-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE SR 3.3.4.1.4 (continued)
| |
| REQUIREMENTS that the calibration remains valid. If any bypass channel's setpoint is nonconservative (i.e., the Functions are bypassed at 26% RTP, either due to open main turbine bypass valves (e.g.,
| |
| required testing or upon actual demand) or other reasons), the affected TSV Closure and TCV Fast Closure, Trip Oil Pressure The Surveillance Low Functions are considered inoperable. Alternatively, the Frequency is bypass channel can be placed in the conservative condition controlled under (nonbypass). If placed in the nonbypass condition, this SR is met the Surveillance with the channel considered OPERABLE.
| |
| Frequency Control Program. The Frequency of 24 months is based on engineering judgement and the reliability of the components.
| |
| SR 3.3.4.1.5 Frequency is This SR ensures that the individual channel response times are controlled under less than or equal to the maximum values assumed in the the Surveillance transient analysis. The EOC-RPT SYSTEM RESPONSE TIME Frequency acceptance criteria are documented in Reference 3.
| |
| Control Program.
| |
| EOC-RPT SYSTEM RESPONSE TIME tests are conducted on a 24 month STAGGERED TEST BASIS. Response times cannot be determined at power because operation of final actuated devices is required. Therefore, the 24 month Frequency is consistent with the typical industry refueling cycle and is based upon plant operating experience, which shows that random failures of instrumentation components that cause serious response time degradation, but not channel failure, are infrequent occurrences.
| |
| (continued) 120 DAEC B 3.3-86 TSCR-123
| |
| | |
| ATWS-RPT Instrumentation B 3.3.4.2 BASES (continued)
| |
| SURVEILLANCE SR 3.3.4.2.1 REQUIREMENTS Performance of the CHANNEL CHECK for the Reactor Vessel Water Level-Low Low Function once every 12 hours ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.
| |
| Agreement criteria are determined by the plant staff based on a The Surveillance combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it Frequency is may be an indication that the instrument has drifted outside its controlled under limit.
| |
| the Surveillance Frequency The Frequency is based upon operating experience that Control Program. demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal but more frequent checks of channels during normal operational use of the displays associated with the required channels of this LCO.
| |
| SR 3.3.4.2.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. The RPT breaker itself is excluded from this testing.
| |
| (continued) 120 DAEC B 3.3-94 TSCR-026A
| |
| | |
| ATWS-RPT Instrumentation B 3.3.4.2 BASES (continued)
| |
| SURVEILLANCE SR 3.3.4.2.2 (continued)
| |
| REQUIREMENTS The Frequency of 12 months is based on the fact that ATWS is The Surveillance considered a very low probability event and is outside the normal Frequency is design basis. Therefore, the surveillance frequency is less controlled under stringent than for safety-related instrumentation.
| |
| the Surveillance Frequency Control Program. SR 3.3.4.2.3 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.
| |
| The Surveillance The Frequency is based upon the assumption of a 12 month Frequency is calibration interval in the determination of the magnitude of controlled under equipment drift in the setpoint analysis.
| |
| the Surveillance Frequency Control Program. SR 3.3.4.2.4 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel.
| |
| The system functional test of the pump breakers is included as The Surveillance part of this Surveillance and overlaps the LOGIC SYSTEM Frequency is FUNCTIONAL TEST to provide complete testing of the assumed controlled under safety function. Therefore, if a breaker is incapable of operating, the Surveillance the associated instrument channel(s) would be inoperable.
| |
| Frequency Control Program. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency.
| |
| this (continued)
| |
| TSCR-120 DAEC B 3.3-95 Amendment 223
| |
| | |
| ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE Because the Ref. 5 analysis made no assumptions regarding the REQUIREMENTS elapsed time between testing of consecutive channels in the same (continued) logic, it is not necessary to remove jumpers/relays blocks or reconnect lifted leads used to prevent actuation of the trip logic during testing of logic channels with instruments in series solely for the purpose of administering the AOT clocks, provided that the AOT allowance is not exceeded on a per instrument channel basis.
| |
| SR 3.3.5.1.1 Performance of the CHANNEL CHECK once every 24 hours ensures that a gross failure of instrumentation has not occurred.
| |
| A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK guarantees that undetected outright channel in time failure is limited to 24 hours; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.
| |
| Agreement criteria are determined by the plant staff, based on a The Surveillance combination of the channel instrument uncertainties, including Frequency is indication and readability. If a channel is outside the criteria, it controlled under may be an indication that the instrument has drifted outside its limit. The Frequency is based upon operating experience that the Surveillance demonstrates channel failure is rare. The CHANNEL CHECK Frequency supplements less formal, but more frequent, checks of channels Control Program. during normal operational use of the displays associated with the channels required by the LCO.
| |
| SR 3.3.5.1.2, SR 3.3.5.1.3, and SR 3.3.5.1.5 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all (continued) 120 DAEC B 3.3-137 TSCR-026A
| |
| | |
| ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE SR 3.3.5.1.2, SR 3.3.5.1.3, and SR 3.3.5.1.5 (continued)
| |
| REQUIREMENTS of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.
| |
| Surveillance The Frequency of 92 days for SR 3.3.5.1.3 is based on the other channels reliability analyses of Reference 5. some channels Surveillance The Frequencies of 31 days and 12 months (SR 3.3.5.1.2 and SR 3.3.5.1.5, respectively) are based upon engineering judgment and the reliability of the components.
| |
| The Surveillance 3 Frequencies are SR 3.3.5.1.4, SR 3.3.5.1.6, SR 3.3.5.1.7, and SR 3.3.5.1.8 controlled under the Surveillance A CHANNEL CALIBRATION is a complete check of the Frequency instrument loop and the sensor. This test verifies the channel Control Program. responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.
| |
| 3 The Surveillance The Frequency of SR 3.3.5.1.4 is based upon the assumption of a Frequencies are 92 day calibration interval in the determination of the magnitude of controlled under equipment drift in the setpoint analysis.
| |
| the Surveillance Frequency The Frequency of SR 3.3.5.1.6 is based upon the assumption of a Control Program. 12 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
| |
| The Frequency of SR 3.3.5.1.7 is based upon the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
| |
| The Frequency of SR 3.3.5.1.8 is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
| |
| (continued) 120 DAEC B 3.3-138 TSCR-026A
| |
| | |
| ECCS Instrumentation B 3.3.5.1 BASES 4
| |
| SURVEILLANCE SR 3.3.5.1.9 REQUIREMENTS (continued) The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel. The system functional testing performed in LCO 3.5.1, LCO 3.5.2, LCO 3.8.1, and LCO 3.8.2 overlaps this Surveillance The Surveillance to complete testing of the assumed safety function.
| |
| Frequency is controlled under The 24 month Frequency is based on the need to perform this the Surveillance Surveillance under the conditions that apply during a plant outage Frequency and the potential for an unplanned transient if the Surveillance Control Program. were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency.
| |
| this REFERENCES 1. UFSAR, Section 5.4.7.
| |
| : 2. UFSAR, Section 6.3.2.
| |
| : 3. UFSAR, Chapter 15.
| |
| : 4. NEDC-32980P, "Safety Analysis Report for Duane Arnold Energy Center Extended Power Uprate," Rev. 1, April 2001.
| |
| : 5. NEDC-30936-P-A, "BWR Owners' Group Technical Specification Improvement Analyses for ECCS Actuation Instrumentation, Part 2," December 1988.
| |
| 120 DAEC B 3.3-139 TSCR-044A
| |
| | |
| RCIC System Instrumentation B 3.3.5.2 BASES (continued)
| |
| SURVEILLANCE As noted in the beginning of the SRs, the SRs for each RCIC REQUIREMENTS System instrumentation Function are found in the SRs column of Table 3.3.5.2-1.
| |
| The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed as follows: (a) for up to 6 hours for Functions 2 and 3; and (b) for up to 6 hours for Function 1, provided the associated Function maintains trip capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 1) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the RCIC will initiate when necessary. Because the Ref. 1 analysis made no assumptions regarding the elapsed time between testing of consecutive channels in the same logic, it is not necessary to remove jumpers/relay blocks or reconnect lifted leads used to prevent actuation of the trip logic during testing of logic channels with instruments in series solely for the purpose of administering the AOT clocks, provided that the AOT allowance is not exceeded on a per instrument channel basis.
| |
| SR 3.3.5.2.1 Performance of the CHANNEL CHECK once every 24 hours ensures that a gross failure of instrumentation has not occurred.
| |
| A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a parameter on other similar channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.3-148 Amendment 223
| |
| | |
| RCIC System Instrumentation B 3.3.5.2 BASES SURVEILLANCE SR 3.3.5.2.1 (continued)
| |
| REQUIREMENTS Agreement criteria are determined by the plant staff based on a The Surveillance combination of the channel instrument uncertainties, including Frequency is indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its controlled under limit.
| |
| the Surveillance Frequency The Frequency is based upon operating experience that Control Program. demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.
| |
| SR 3.3.5.2.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is The Surveillance acceptable because all of the other required contacts of the relay Frequency is are verified by other Technical Specifications and non-Technical controlled under Specifications tests at least once per refueling interval with applicable extenstions.
| |
| the Surveillance Frequency The Frequency of 92 days is based on the reliability analysis of Control Program. Reference 1.
| |
| SR 3.3.5.2.3 and SR 3.3.5.2.4 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel The Surveillance responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel Frequency is adjusted to account for instrument drifts between successive controlled under calibrations consistent with the plant specific setpoint the Surveillance methodology.
| |
| Frequency Control Program. The Frequency of SR 3.3.5.2.3 is based upon the assumption of a 12 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
| |
| (continued) 120 DAEC B 3.3-149 TSCR-026A
| |
| | |
| RCIC System Instrumentation B 3.3.5.2 BASES SURVEILLANCE SR 3.3.5.2.3 and SR 3.3.5.2.4 (continued)
| |
| REQUIREMENTS The Frequency of SR 3.3.5.2.4 is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
| |
| 4 SR 3.3.5.2.5 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the The Surveillance OPERABILITY of the required initiation logic for a specific Frequency is channel. The system functional testing performed in LCO 3.5.3 controlled under overlaps this Surveillance to provide complete testing of the safety the Surveillance function.
| |
| Frequency Control Program. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency.
| |
| this REFERENCES 1. GENE-770-06-2, "Addendum to Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," February 1991.
| |
| TSCR-120 DAEC B 3.3-150 Amendment 223
| |
| | |
| Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE SR 3.3.6.1.1 and SR 3.3.6.1.2 REQUIREMENTS (continued) Performance of the CHANNEL CHECK once every 12 hours or once every 24 hours ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.
| |
| Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including The Surveillance indication and readability. If a channel is outside the criteria, it Frequency is may be an indication that the instrument has drifted outside its controlled under limit.
| |
| the Surveillance Frequency The Frequencies are based on operating experience that Control Program. demonstrates channel failure is rare. The CHANNEL CHECK The Frequency is supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.
| |
| 2 SR 3.3.6.1.3, and SR 3.3.6.1.4 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.
| |
| (continued) 120 DAEC B 3.3-186 TSCR-026A
| |
| | |
| Primary Containment Isolation Instrumentation B 3.3.6.1 BASES 2
| |
| SURVEILLANCE SR 3.3.6.1.3, and SR 3.3.6.1.4 (continued)
| |
| Surveillance REQUIREMENTS Surveillance of some channels The Surveillance The 92 day Frequency of SR 3.3.6.1.4 is based on the reliability Frequency is analyses described in References 5 and 6. The 31 day controlled under Frequency of SR 3.3.6.1.3 is based on engineering judgment and the reliability of the components. other channels the Surveillance 3 Frequency SR 3.3.6.1.5, SR 3.3.6.1.6, SR 3.3.6.1.7 and SR 3.3.6.1.8 Control Program.
| |
| A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel The Surveillance adjusted to account for instrument drifts between successive Frequency is calibrations consistent with the plant specific setpoint controlled under methodology.
| |
| the Surveillance Frequency The Frequency of SR 3.3.6.1.5 is based on the assumption of a Control Program. 92 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
| |
| The Frequency of SR 3.3.6.1.6 is based on the assumption of a 184 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
| |
| The Frequency of SR 3.3.6.1.7 is based on the assumption of a 12 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
| |
| The Frequency of SR 3.3.6.1.8 is based on the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
| |
| (continued) 120 DAEC B 3.3-187 TSCR-044A
| |
| | |
| Primary Containment Isolation Instrumentation B 3.3.6.1 BASES 4
| |
| SURVEILLANCE SR 3.3.6.1.9 REQUIREMENTS (continued) The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the The Surveillance OPERABILITY of the required isolation logic for a specific Frequency is channel. The system functional testing performed on PCIVs in controlled under LCO 3.6.1.3 overlaps this Surveillance to provide complete testing of the assumed safety function. The 24 month Frequency is the Surveillance based on the need to perform this Surveillance under the Frequency conditions that apply during a plant outage and the potential for an Control Program. unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency.
| |
| this REFERENCES 1. UFSAR, Section 6.2.
| |
| : 2. UFSAR, Chapter 15.
| |
| : 3. NEDO-31466, "Technical Specification Screening Criteria Application and Risk Assessment," November 1987.
| |
| : 4. UFSAR, Section 9.3.4.2.
| |
| : 5. NEDC-31677P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation,"
| |
| July 1990.
| |
| : 6. NEDC-30851P-A Supplement 2, "Technical Specifications Improvement Analysis for BWR Isolation Instrumentation Common to RPS and ECCS Instrumentation," March 1989.
| |
| : 7. UFSAR, Section 7.3.
| |
| : 8. UFSAR, Section 15.2.1.5.
| |
| (continued) 120 DAEC B 3.3-188 TSCR-044A
| |
| | |
| Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES SURVEILLANCE The Surveillances are modified by a Note to indicate that when a REQUIREMENTS channel is placed in an inoperable status solely for performance of (continued) required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains secondary containment isolation capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Refs. 4 and 5) assumption of the average time required to perform channel surveillance. That analysis demonstrated the 6 hour testing allowance does not significantly reduce the probability that the SCIV/Ds will isolate the associated penetration flow paths and that the SBGT System will initiate when necessary.
| |
| SR 3.3.6.2.1 and SR 3.3.6.2.2 Performance of the CHANNEL CHECK either once every 12 hours or once every 24 hours ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION. Agreement criteria are determined by the plant staff based on a combination of the channel instrument The Surveillance uncertainties, including indication and readability. If a channel is Frequency is outside the criteria, it may be an indication that the instrument has controlled under drifted outside its limit.
| |
| the Surveillance Frequency The Frequencies are based on operating experience that Control Program. demonstrates channel failure is rare. The CHANNEL CHECK The Frequency is supplements less formal, but more frequent, checks of channel status during normal operational use of the displays associated with channels required by the LCO.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.3-198 Amendment 223
| |
| | |
| Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES 2
| |
| SURVEILLANCE SR 3.3.6.2.3 REQUIREMENTS (continued) A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state The Surveillance of a single contact of the relay. This clarifies what is an Frequency is acceptable CHANNEL FUNCTIONAL TEST of a relay. This is controlled under acceptable because all of the other required contacts of the relay the Surveillance are verified by other Technical Specifications and non-Technical Frequency Specifications tests at least once per refueling interval with Control Program. applicable extensions.
| |
| The Frequency of 92 days is based on the reliability analysis of References 4 and 5.
| |
| 3 SR 3.3.6.2.4 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range The Surveillance and accuracy. CHANNEL CALIBRATION leaves the channel Frequency is adjusted to account for instrument drifts between successive controlled under calibrations consistent with the plant specific setpoint methodology.
| |
| the Surveillance Frequency The Frequency of SR 3.3.6.2.4 is based on the assumption of a Control Program. 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
| |
| 4 SR 3.3.6.2.5 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required isolation logic for a specific channel. The system functional testing performed on SCIV/Ds and the SBGT System in LCO 3.6.4.2 and LCO 3.6.4.3, respectively, overlaps this Surveillance to provide complete testing of the assumed safety function.
| |
| The Surveillance Frequency is The 24 month Frequency is based on the need to perform this controlled under Surveillance under the conditions that apply during a plant outage the Surveillance and the potential for an unplanned transient if the Surveillance Frequency were performed with the reactor at power.
| |
| Control Program.
| |
| (continued) 120 DAEC B 3.3-199 TSCR-026A
| |
| | |
| Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES 4
| |
| SURVEILLANCE SR 3.3.6.2.5 (continued)
| |
| REQUIREMENTS Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency. this REFERENCES 1. UFSAR, Section 6.2.3.
| |
| : 2. UFSAR, Chapter 15.
| |
| : 3. UFSAR, Section 15.2.1.
| |
| : 4. NEDC-30851P-A Supplement 2, "Technical Specifications Improvement Analysis for BWR Isolation Instrumentation Common to RPS and ECCS Instrumentation," March 1989.
| |
| : 5. NEDC-31677P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation,"
| |
| July 1990.
| |
| 120 DAEC B 3.3-200 TSCR-044A
| |
| | |
| LLS Instrumentation B 3.3.6.3 BASES SURVEILLANCE does not significantly reduce the probability that the LLS valves REQUIREMENTS will initiate when necessary.
| |
| (continued)
| |
| SR 3.3.6.3.1, and SR 3.3.6.3.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an The Surveillance acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay Frequency is are verified by other Technical Specifications and non-Technical controlled under Specifications tests at least once per refueling interval with the Surveillance applicable extensions.
| |
| Frequency Control Program. The 92 day Frequency is based on the reliability analysis of Reference 3.
| |
| A portion of the SRV tailpipe pressure switch channels is located inside the primary containment and is not available for testing during reactor operation. Therefore, SR 3.3.6.3.1 is only required on that portion of the channel that is outside primary containment.
| |
| SR 3.3.6.3.3, SR 3.3.6.3.4, and SR 3.3.6.3.5 CHANNEL CALIBRATION is a complete check of the instrument loop and sensor. This test verifies the channel responds to the The Surveillance measured parameter within the necessary range and accuracy.
| |
| Frequency is CHANNEL CALIBRATION leaves the channel adjusted to account controlled under for instrument drifts between successive calibrations consistent the Surveillance with the plant specific setpoint methodology. The Frequency of once every 92 days for SR 3.3.6.3.3, 184 days for SR 3.3.6.3.4, Frequency and 24 months for SR 3.3.6.3.5 is based on the assumption of the Control Program. corresponding calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
| |
| (continued) 120 DAEC B 3.3-207 TSCR-026A
| |
| | |
| LLS Instrumentation B 3.3.6.3 BASES 4
| |
| SURVEILLANCE SR 3.3.6.3.6 REQUIREMENTS (continued) The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required actuation logic for a specified The Surveillance channel. The system functional testing performed in LCO 3.4.3, Frequency is "Safety Relief Valves (SRVs)" and LCO 3.6.1.5, "Low-Low Set controlled under (LLS) Safety Relief Valves (SRVs)," for SRVs overlaps this test to the Surveillance provide complete testing of the assumed safety function.
| |
| Frequency Control Program. The Frequency of once every 24 months for SR 3.3.6.3.6 is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency. this REFERENCES 1. UFSAR, Figure 7.6-31.
| |
| : 2. NEDE-30021-P, Low-Low Set Relief Logic System and Lower MSIV Water Level Trip for the DAEC, January 1983.
| |
| : 3. GENE-770-06-1, "Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," February 1991.
| |
| 4 UFSAR, Chapter 15.
| |
| 120 DAEC B 3.3-208 TSCR-044A
| |
| | |
| SFU System Instrumentation B 3.3.7.1 BASES ACTIONS A.1, and A.2 (continued)
| |
| The 1 hour Completion Time is intended to allow the operator time to place the SFU subsystem(s) in the isolation mode of operation, and is acceptable because it minimizes risk while allowing time for restoration of channels, or for placing the associated SFU in its safety mode, or for entering the applicable Conditions and Required Actions for the inoperable SFU subsystem(s).
| |
| SURVEILLANCE The Surveillances are modified by a Note to indicate that when a REQUIREMENTS channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours, provided the other channel is OPERABLE. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Refs. 4 and 5) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the SFU System will initiate when necessary.
| |
| SR 3.3.7.1.1 Performance of the CHANNEL CHECK once every 24 hours ensures that a gross failure of instrumentation has not occurred.
| |
| A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.3-212 Amendment 223
| |
| | |
| SFU System Instrumentation B 3.3.7.1 BASES SURVEILLANCE SR 3.3.7.1.1 (continued)
| |
| REQUIREMENTS The Surveillance Agreement criteria are determined by the plant staff, based on a Frequency is combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it controlled under may be an indication that the instrument has drifted outside its the Surveillance limit.
| |
| Frequency Control Program. The Frequency is based upon operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channel status during normal operational use of the displays associated with channels required by the LCO.
| |
| SR 3.3.7.1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is The Surveillance acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Frequency is Specifications tests at least once per refueling interval with controlled under applicable extensions.
| |
| the Surveillance Frequency The Frequency of 92 days is based on the reliability analyses of Control Program. References 4 and 5.
| |
| SR 3.3.7.1.3 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range The Surveillance and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive Frequency is calibrations consistent with the plant specific setpoint controlled under methodology.
| |
| the Surveillance Frequency The Frequency is based upon the assumption of a 24 month Control Program. calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
| |
| (continued) 120 DAEC B 3.3-213 TSCR-026A
| |
| | |
| SFU System Instrumentation B 3.3.7.1 BASES SURVEILLANCE SR 3.3.7.1.4 REQUIREMENTS (continued) The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the The Surveillance OPERABILITY of the required initiation logic for a specific Frequency is channel. The system functional testing performed in LCO 3.7.4, "Standby Filter Unit (SFU) System," overlaps this Surveillance to controlled under provide complete testing of the assumed safety function.
| |
| the Surveillance Frequency The 24 month Frequency is based on operating experience that Control Program. has shown these components usually pass the Surveillance when performed at the 24 month Frequency.
| |
| this REFERENCES 1. UFSAR, Section 15.2.
| |
| : 2. UFSAR, Section 6.4.4.
| |
| : 3. [Deleted]
| |
| : 4. GENE-770-06-1, "Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," February 1991.
| |
| : 5. NEDC-31677P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation,"
| |
| July 1990.
| |
| 120 DAEC B 3.3-214 TSCR-044A
| |
| | |
| LOP Instrumentation B 3.3.8.1 BASES ACTIONS C.1 (continued)
| |
| If the Required Action and associated Completion Time is not met, the associated Function is not capable of performing the intended function. Therefore, the associated DG(s) is declared inoperable immediately. This requires entry into applicable Conditions and Required Actions of LCO 3.8.1 and LCO 3.8.2, which provide appropriate actions for the inoperable DG(s).
| |
| SURVEILLANCE As noted at the beginning of the SRs, the SRs for each LOP REQUIREMENTS instrumentation Function are located in the SRs column of Table 3.3.8.1-1.
| |
| The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 2 hours provided the associated Function maintains DG initiation capability. Upon completion of the Surveillance, or expiration of the 2 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken.
| |
| SR 3.3.8.1.1 and SR 3.3.8.1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state The Surveillance of a single contact of the relay. This clarifies what is an Frequency is acceptable CHANNEL FUNCTIONAL TEST of a relay. This is controlled under acceptable because all of the other required contacts of the relay the Surveillance are verified by other Technical Specifications and non-Technical Frequency Specifications tests at least once per refueling interval with Control Program. applicable extensions.
| |
| The Frequency is The Frequencies of 31 days and 12 months are based on operating experience with regard to channel OPERABILITY and drift, which demonstrates that failure of more than one channel of a given Function in any 31 day interval or 12 month interval (as appropriate) is a rare event. this (continued) 120 DAEC B 3.3-222 TSCR-026A
| |
| | |
| LOP Instrumentation B 3.3.8.1 BASES 2
| |
| SURVEILLANCE SR 3.3.8.1.3 and SR 3.3.8.1.4 REQUIREMENTS (continued) A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range The Surveillance and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive Frequency is calibrations consistent with the plant specific setpoint controlled under methodology. Any setpoint adjustment shall be consistent with the Surveillance the assumptions of the current plant specific setpoint Frequency methodology.
| |
| Control Program.
| |
| The Frequency is The Frequencies are based upon the assumption of either a 12 month or 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
| |
| 3 SR 3.3.8.1.5 The Surveillance The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the Frequency is OPERABILITY of the required actuation logic for a specific controlled under channel. The system functional testing performed in LCO 3.8.1 the Surveillance and LCO 3.8.2 overlaps this Surveillance to provide complete Frequency testing of the assumed safety functions.
| |
| Control Program.
| |
| The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency.
| |
| this REFERENCES 1. UFSAR, Section 6.2.
| |
| : 2. UFSAR, Section 6.3.
| |
| : 3. UFSAR, Chapter 15.
| |
| 120 DAEC B 3.3-223 TSCR-044A
| |
| | |
| RPS Electric Power Monitoring B 3.3.8.2 BASES SURVEILLANCE SR 3.3.8.2.1 (continued)
| |
| REQUIREMENTS As noted in the Surveillance, the CHANNEL FUNCTIONAL TEST is only required to be performed while the plant is in a condition in which the loss of the RPS bus will not jeopardize steady state The Surveillance power operation (the design of the system is such that the power Frequency is source must be removed from service to conduct the Surveillance). The 24 hours is intended to indicate an outage of controlled under sufficient duration to allow for scheduling and proper performance the Surveillance of the Surveillance.
| |
| Frequency Control Program. The 184 day Frequency and the Note in the Surveillance are based on guidance provided in Generic Letter 91-09 (Ref. 2).
| |
| SR 3.3.8.2.2 CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies that the channel responds The Surveillance to the measured parameter within the necessary range and Frequency is accuracy. CHANNEL CALIBRATION leaves the channel adjusted controlled under to account for instrument drifts between successive calibrations the Surveillance consistent with the plant specific setpoint methodology.
| |
| Frequency The Frequency is based on the assumption of a 24 month Control Program. calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
| |
| SR 3.3.8.2.3 Performance of a system functional test demonstrates that, with a required system actuation (simulated or actual) signal, the system will automatically trip open the associated EPA. Only one signal per EPA is required to be tested. This Surveillance overlaps with the CHANNEL CALIBRATION to provide complete testing of the safety function. The system functional test of the Class 1E circuit breakers is included as part of this test to provide complete testing of the safety function. If the breakers are incapable of operating, the associated EPA would be inoperable.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.3-229 Amendment 223
| |
| | |
| RPS Electric Power Monitoring B 3.3.8.2 BASES SURVEILLANCE SR 3.3.8.2.3 (continued)
| |
| REQUIREMENTS The Surveillance The 24 month Frequency is based on the need to perform this Frequency is Surveillance under the conditions that apply during a plant outage controlled under and the potential for an unplanned transient if the Surveillance the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillance Frequency Control when performed at the 24 month Frequency.
| |
| Program. this REFERENCES 1. UFSAR, Section 7.2.1.1.2.
| |
| : 2. NRC Generic Letter 91-09, "Modification of Surveillance Interval for the Electrical Protective Assemblies in Power Supplies for the Reactor Protection System."
| |
| TSCR-120 DAEC B 3.3-230 Amendment 223
| |
| | |
| Recirculation Loops Operating B 3.4.1 BASES SURVEILLANCE SR 3.4.1.1 (continued)
| |
| REQUIREMENTS Analyses indicate that above 69.4% RTP the LPCI Loop Select Logic could be expected to function at a speed differential up to 14% of average recirculation pump speed with the specification limit set at approximately +/- 10% of average recirculation pump speed to provide margin. Below 69.4% RTP the Loop Select Logic would be expected to function at a speed differential up to 20% of average recirculation pump speed with the specification limit set at approximately +/- 15% of average recirculation pump speed to provide margin. If the reactor is operating on one recirculation pump, the Loop Select Logic trips the pump before making the loop selection. The mismatch is measured in terms of percent of the speed of one recirculation pump compared to the speed of the other recirculation pump. If the speed mismatch exceeds the specified limits and cannot be restored within two hours, one recirculation pump shall be tripped. The SR is not The Surveillance required when both loops are not in operation since the mismatch Frequency is limits are meaningless during single loop operation. The controlled under Surveillance must be performed within 24 hours after both loops are in operation. The 24 hour Frequency is consistent with the the Surveillance Surveillance Frequency for jet pump OPERABILITY verification Frequency and has been shown by operating experience to be adequate to Control Program. detect off normal jet pump loop flows in a timely manner.
| |
| SR 3.4.1.2 This SR ensures the reactor THERMAL POWER and core flow are within appropriate parameter limits to prevent uncontrolled The Surveillance power oscillations. At low recirculation flows and high reactor Frequency is power, the reactor exhibits increased susceptibility to thermal controlled under hydraulic instability if operation is permitted in the Exclusion Region shown in the Core Operating Limits Report. The 24 hour the Surveillance Frequency is based on operating experience and the operators' Frequency inherent knowledge of reactor status, including significant Control Program. changes in THERMAL POWER and core flow.
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| (continued) 120 DAEC B 3.4-8 TSCR-044
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| | |
| Jet Pumps B 3.4.2 BASES (continued)
| |
| SURVEILLANCE SR 3.4.2.1 (continued)
| |
| REQUIREMENTS Individual jet pumps in a recirculation loop normally do not have the same flow. The unequal flow is due to the drive flow manifold, which does not distribute flow equally to all risers. The flow (or jet pump diffuser to lower plenum differential pressure) pattern or relationship of one jet pump to the loop average is repeatable. An appreciable change in this relationship is an indication that increased (or reduced) resistance has occurred in one of the jet pumps. This may be indicated by an increase in the relative flow for a jet pump that has experienced beam cracks.
| |
| The deviations from normal are considered indicative of a The Surveillance potential problem in the recirculation drive flow or jet pump system Frequency is (Ref. 2). Normal flow ranges and established jet pump flow and controlled under differential pressure patterns are established by plotting historical the Surveillance data as discussed in Reference 2.
| |
| Frequency Control Program. The 24 hour Frequency has been shown by operating experience to be timely for detecting jet pump degradation and is consistent with the Surveillance Frequency for recirculation loop OPERABILITY verification.
| |
| This SR is modified by three Notes. Notes 1 and 2 affect the entire SR. The third Note only affects criterion c. Note 1 allows this Surveillance not to be performed until 4 hours after the associated recirculation loop is in operation, since these checks can only be performed during jet pump operation. The 4 hours is an acceptable time to establish conditions appropriate for data collection and evaluation.
| |
| Note 2 allows this SR not to be performed when THERMAL POWER is 21.7% of RTP. During low flow conditions, jet pump noise approaches the threshold response of the associated flow instrumentation and precludes the collection of repeatable and meaningful data.
| |
| (continued) 120 DAEC B 3.4-13 TSCR-044
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| | |
| SRVs and SVs B 3.4.3 BASES SURVEILLANCE SR 3.4.3.2 (continued)
| |
| REQUIREMENTS pressure and flow are adequate to perform the test. The 12 hours allowed for manual actuation after the required pressure and flow are reached is sufficient to achieve stable conditions for testing and provides a reasonable time to complete the SR. If a valve fails to actuate due only to the failure of the solenoid but is capable of opening on overpressure, the safety function of the SRV is not considered inoperable.
| |
| The Surveillance Frequency is This SR is not applicable to the SVs, due to their design which controlled under does not include the manual relief capability, nor do they have a the Surveillance discharge line that can become blocked.
| |
| Frequency The 24 month Surveillance Frequency is consistent with the Control Program. guidance of NUREG 1482, part 4.3.4 (Ref. 4), where the staff recommends reducing the number of challenges to dual function relief valves, because failure in the open position is equivalent to a small break LOCA. Operating experience has shown that these this components usually pass the Surveillance when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| REFERENCES 1. UFSAR, Section 5.2.2.2.1.
| |
| : 2. UFSAR, Section 15.1.2.
| |
| : 3. ASME, Boiler and Pressure Vessel Code, Section XI.
| |
| : 4. NUREG 1482, Guidelines for Inservice Testing at Nuclear Power Plants.
| |
| 120 DAEC B 3.4-20 TSCR-044A
| |
| | |
| RCS Operational LEAKAGE B 3.4.4 BASES ACTIONS C.1 and C.2 (continued)
| |
| If any Required Action and associated Completion Time of Condition A or B is not met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours and to MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant safety systems.
| |
| SURVEILLANCE SR 3.4.4.1 REQUIREMENTS The RCS LEAKAGE is monitored by a variety of instruments designed to provide alarms when LEAKAGE is indicated and to quantify the various types of LEAKAGE. Leakage detection instrumentation is discussed in more detail in the Bases for LCO 3.4.5, "RCS Leakage Detection Instrumentation." Sump level and flow rate are typically monitored to determine actual LEAKAGE rates; however, other methods may be used to quantify LEAKAGE within the guidelines of References 4 and 5. It is permissible to use pre-existing information, in conjunction with secondary measurements (e.g., Drywell pressure and temperature), to verify that LEAKAGE remains within limits by looking for step changes in conditions or to perform calculations to estimate LEAKAGE. The The Surveillance complete failure to demonstrate that RCS LEAKAGE is within limits, Frequency is on the required Frequency, constitutes a failure to meet this SR, controlled under notwithstanding entrance into Conditions and Required Actions of the Surveillance LCO 3.4.5.
| |
| Frequency In conjuction with alarms and other administrative controls, a 12 the Control Program. hour Frequency for this Surveillance is appropriate for identifying LEAKAGE and for tracking required trends (Ref. 5).
| |
| (continued) 120 DAEC B 3.4-25 TSCR-045
| |
| | |
| RCS Leakage Detection Instrumentation B 3.4.5 BASES ACTIONS D.1 and D.2 (continued)
| |
| If any Required Action of Condition A or C cannot be met within the associated Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to perform the actions in an orderly manner and without challenging plant systems.
| |
| SURVEILLANCE SR 3.4.5.1 REQUIREMENTS The Surveillance This SR is for the performance of a CHANNEL CHECK of the Frequency is required Primary Containment Air Sampling System. The check controlled under gives reasonable confidence that the channel is operating properly. The Frequency of 12 hours is based on instrument the Surveillance reliability and is reasonable for detecting off normal conditions.
| |
| Frequency Control Program. SR 3.4.5.2 This SR is for the performance of a CHANNEL FUNCTIONAL TEST of the required Primary Containment Air Sampling System instrumentation, equipment drain sump flow integrator and floor drain sump flow integrator. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling The Surveillance interval with applicable extensions. These tests ensure that the Frequency is monitors can perform their function in the desired manner and also verifies the Primary Containment Air Sampling System alarm controlled under functions properly. The Frequency of 31 days considers the Surveillance instrument reliability, and operating experience has shown it Frequency proper for detecting degradation.
| |
| Control Program.
| |
| (continued) 120 DAEC B 3.4-32 TSCR-045
| |
| | |
| RCS Leakage Detection Instrumentation B 3.4.5 BASES SURVEILLANCE SR 3.4.5.3 REQUIREMENTS (continued) This SR is for the performance of a CHANNEL FUNCTIONAL TEST of required equipment drain sump fill and sump pump out timers and floor drain sump fill and sump pump out timers. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single The Surveillance contact of the relay. This clarifies what is an acceptable Frequency is CHANNEL FUNCTIONAL TEST of a relay. This is acceptable controlled under because all of the other required contacts of the relay are verified the Surveillance by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extentions.
| |
| Frequency The Frequency of 92 days considers channel reliability. Operating Control Program. experience has proven this Frequency is acceptable.
| |
| SR 3.4.5.4 and SR 3.4.5.5 These SRs are for the performance of a CHANNEL CALIBRATION of required Primary Containment Air Sampling System instrumentation, equipment drain sump flow integrator, floor drain sump flow integrator, equipment drain sump fill and sump pump out timers and floor drain sump fill and sump pump The Surveillance out timers. The calibration verifies the accuracy of the instrument Frequency is string, excluding the level elements located inside containment.
| |
| controlled under The level elements have no adjustable parts and thus, do not require calibration. The Frequency of 92 days or 12 months the Surveillance considers channel reliability. Operating experience has proven Frequency these Frequencies are acceptable.
| |
| Control Program.
| |
| REFERENCES 1. UFSAR Section 3.1.2.4.1.
| |
| : 2. GEAP-5620, "Failure Behavior in ASTM A106B Pipes Containing Axial Through-Wall Flaws," April 1968.
| |
| : 3. NUREG-75/067, "Investigation and Evaluation of Cracking in Austenitic Stainless Steel Piping of Boiling Water Reactors," October 1975.
| |
| : 4. UFSAR, Section 5.2.5.2.3.
| |
| : 5. DAEC Operating License Amendment # 169, 9-19-90.
| |
| 120 DAEC B 3.4-32a TSCR-045
| |
| | |
| RCS Specific Activity B 3.4.6 BASES (continued)
| |
| SURVEILLANCE SR 3.4.6.1 REQUIREMENTS The Surveillance This Surveillance is performed to ensure iodine remains within Frequency is limits during normal operation. The analysis is performed using controlled under the filtrate from a 0.45µ filter. The 7 day Frequency is adequate to Surveillance trend changes in the iodine activity level.
| |
| Frequency Control Program. This SR is modified by a Note that requires this Surveillance to be performed only in MODE 1 because the level of fission products generated in other MODES is much less.
| |
| REFERENCES 1. 10 CFR 50.67
| |
| : 2. UFSAR, Sections 15.0.8 and 15.0.9.
| |
| : 3. UFSAR, Section 15.2.1.5 120 DAEC B 3.4-36 TSCR-044A
| |
| | |
| RHR Shutdown Cooling System - Hot Shutdown B 3.4.7 BASES ACTIONS B.1, B.2, and B.3 (continued)
| |
| With no RHR shutdown cooling subsystem and no recirculation pump in operation, except as permitted by LCO Note 1, reactor coolant circulation by the RHR shutdown cooling subsystem or recirculation pump must be restored without delay. Until RHR or recirculation pump operation is re-established, an alternate method of reactor coolant circulation must be placed into service.
| |
| This will provide the necessary circulation for monitoring coolant temperature. The 1 hour Completion Time is based on the coolant circulation function and is modified such that the 1 hour is applicable separately for each occurrence involving a loss of coolant circulation. Furthermore, verification of the functioning of the alternate method must be reconfirmed every 12 hours thereafter. This will provide assurance of continued temperature monitoring capability. An alternate method of reactor coolant circulation that can be used includes (but is not limited to) Reactor Water Cleanup System.
| |
| During the period when the reactor coolant is being circulated by an alternate method (other than by the required RHR shutdown cooling subsystem or recirculation pump), the reactor coolant temperature and pressure must be periodically monitored to ensure proper function of the alternate method. The once per hour Completion Time is deemed appropriate.
| |
| SURVEILLANCE SR 3.4.7.1 REQUIREMENTS This Surveillance verifies that one required RHR shutdown cooling The Surveillance subsystem or recirculation pump is in operation and circulating Frequency is reactor coolant. The RHR shutdown cooling subsystem or controlled under recirculation pump flow rate is determined by the flow rate the Surveillance necessary to provide sufficient decay heat removal capability.
| |
| Frequency The Frequency of 12 hours is sufficient in view of other visual and Control Program. audible indications available to the operator for monitoring the RHR subsystem in the control room.
| |
| This Surveillance is modified by a Note allowing sufficient time to align the RHR System for shutdown cooling operation after clearing the RCIC Steam Supply Line Pressure - Low isolation pressure, or for placing a recirculation pump in operation. The Note takes exception to the requirements of the Surveillance being met (i.e., forced coolant circulation is not required for this initial 2 hour period), which also allows entry into the Applicability (continued)
| |
| TSCR-120 DAEC B 3.4-41 Amendment 223
| |
| | |
| RHR Shutdown Cooling System - Cold Shutdown B 3.4.8 BASES ACTIONS B.1 and B.2 (continued)
| |
| With no RHR shutdown cooling subsystem and no recirculation pump in operation except as permitted by LCO Note 1, and until RHR or recirculation pump operation is re-established, an alternate method of reactor coolant circulation must be placed into service. This alternate method may consist of the losses to ambient surroundings if such losses are sufficiently large so as to prevent RCS temperature from increasing and if natural circulation has been established. This will provide the necessary circulation for monitoring coolant temperature. The 1 hour Completion Time is based on the coolant circulation function and is modified such that the 1 hour is applicable separately for each occurrence involving a loss of coolant circulation. Furthermore, verification of the functioning of the alternate method must be reconfirmed every 12 hours thereafter. This will provide assurance of continued temperature monitoring capability. Alternate methods of reactor coolant circulation that can be used include (but are not limited to) raising reactor water level above the minimum natural circulation level (i.e., lowest turnaround point for water in the steam separator) and Reactor Water Cleanup System.
| |
| During the period when the reactor coolant is being circulated by an alternate method (other than by the required RHR Shutdown Cooling System or recirculation pump), the reactor coolant temperature and pressure must be periodically monitored to ensure proper function of the alternate method. The once per hour Completion Time is deemed appropriate.
| |
| SURVEILLANCE SR 3.4.8.1 REQUIREMENTS The Surveillance This Surveillance verifies that one required RHR shutdown cooling Frequency is subsystem or recirculation pump is in operation and circulating controlled under reactor coolant. The RHR shutdown cooling subsystem or the Surveillance recirculation pump flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability.
| |
| Frequency The Frequency of 12 hours is sufficient in view of other visual and Control Program. audible indications available to the operator for monitoring the RHR subsystem in the control room.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.4-47 Amendment 223
| |
| | |
| RCS P/T Limits B 3.4.9 BASES ACTIONS C.1 and C.2 (continued)
| |
| Operation outside the P/T limits in other than MODES 1, 2, and 3 (including defueled conditions) must be corrected so that the RCPB is returned to a condition that has been verified by stress analyses. The Required Action must be initiated without delay and continued until the limits are restored.
| |
| Besides restoring the P/T limit parameters to within limits, an evaluation is required to determine if RCS operation is allowed.
| |
| This evaluation must verify that the RCPB integrity is acceptable and must be completed before approaching criticality or heating up to > 212°F. Several methods may be used, including comparison with pre-analyzed transients, new analyses, or inspection of the components. ASME Code, Section XI, Appendix E (Ref. 6), may be used to support the evaluation; however, its use is restricted to evaluation of the beltline.
| |
| Condition C is modified by a Note requiring Required Action C.2 be completed whenever the Condition is entered. The Note emphasizes the need to perform the evaluation of the effects of the excursion outside the allowable limits. Restoration alone per Required Action C.1 is insufficient because higher than analyzed stresses may have occurred and may have affected the RCPB integrity.
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| SURVEILLANCE SR 3.4.9.1 REQUIREMENTS The Surveillance Verification that operation is within limits is required every periodically Frequency is controlled 30 minutes when RCS pressure and temperature conditions are under the Surveillance undergoing planned changes. This Frequency is considered reasonable in view of the control room indication available to Frequency Control monitor RCS status. Also, since temperature rate of change limits Program. are specified in hourly increments, 30 minutes permits a this Frequency reasonable time for assessment and correction of minor deviations. The limits of Figure 3.4.9-1 are met when operation is to the right of the applicable limit curve.
| |
| (continued) 120 DAEC B 3.4-54 TSCR-017
| |
| | |
| RCS P/T Limits B 3.4.9 BASES SURVEILLANCE SR 3.4.9.1 (continued)
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| REQUIREMENTS Surveillance for heatup, cooldown, or inservice leakage and hydrostatic testing may be initiated and discontinued when the criteria given in the relevant plant procedure for starting and ending the activity are satisfied. During heatups and cooldowns, the temperatures at the reactor vessel shell adjacent to the shell NOTE: There are no changes on this page, flange, the reactor vessel bottom drain, recirculation loops A and it is included for B, and the reactor vessel bottom head shall be monitored. During completeness only. inservice hydrostatic or leak testing, the reactor vessel metal temperatures at the outside surface of the bottom head in the vicinity of the control rod drive housing and reactor vessel shell adjacent to the shell flange shall be monitored.
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| This SR has been modified with a Note that requires this Surveillance to be performed only during system heatup and cooldown operations and inservice leakage and hydrostatic testing.
| |
| SR 3.4.9.2 A separate limit is used when the reactor is approaching criticality.
| |
| Consequently, the RCS pressure and temperature must be verified within the appropriate limits before withdrawing control rods that will make the reactor critical. The limits of Figure 3.4.9-1 are met when operation is to the right of the applicable limit curve.
| |
| Performing the Surveillance within 15 minutes before control rod withdrawal for the purpose of achieving criticality provides adequate assurance that the limits will not be exceeded between the time of the Surveillance and the time of the control rod withdrawal.
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| SR 3.4.9.3 and SR 3.4.9.4 Differential temperatures within the applicable limits ensure that thermal stresses resulting from the startup of an idle recirculation pump will not exceed design allowances. In addition, compliance with these limits ensures that the assumptions of the analysis for the startup of an idle recirculation pump (Ref. 8) are satisfied.
| |
| (continued)
| |
| DAEC B 3.4-55 TSCR-017
| |
| | |
| RCS P/T Limits B 3.4.9 BASES SURVEILLANCE SR 3.4.9.3 and SR 3.4.9.4 (continued)
| |
| REQUIREMENTS Performing the Surveillance within 15 minutes before starting the idle recirculation pump provides adequate assurance that the limits will not be exceeded between the time of the Surveillance and the time of the idle pump start.
| |
| For SR 3.4.9.3, an acceptable means of measuring Reactor Pressure Vessel (RPV) coolant temperature is by using the saturation temperature corresponding to reactor steam dome pressure.
| |
| Acceptable means of demonstrating compliance with the temperature differential requirement in SR 3.4.9.4 include but are not limited to comparing the temperatures of the operating recirculation loop and the idle loop. The idle loop and RPV coolant temperature using saturation temperature corresponding to reactor steam dome pressure, or the idle loop and the bottom head coolant temperature with flow through the bottom head drain.
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| SR 3.4.9.3 and SR 3.4.9.4 have been modified by a Note that requires the Surveillance to be met only in MODES 1, 2, 3, and 4 during a recirculation pump startup, since this is when the stresses occur. In MODE 5, the overall stress on limiting components is lower. Therefore, T limits are not required.
| |
| SR 3.4.9.5, SR 3.4.9.6, and SR 3.4.9.7 Limits on temperature at the reactor vessel head flange and the shell adjacent to the head flange are generally bounded by the other P/T limits during system heatup and cooldown. However, operations approaching MODE 4 from MODE 5 and in MODE 4 with RCS temperature less than or equal to certain specified values require assurance that these temperatures meet the LCO limits.
| |
| SR 3.4.9.5 requires that temperatures at the reactor vessel head flange and the shell adjacent to the head flange must be verified the Surveillance Frequency to be above the limits within 30 minutes before and while tensioning the vessel head bolting studs to ensure that once the head is tensioned the limits are satisfied. When in MODE 4 with (continued) 120 DAEC B 3.4-56 TSCR-017
| |
| | |
| RCS P/T Limits B 3.4.9 BASES SURVEILLANCE SR 3.4.9.5, SR 3.4.9.6, and SR 3.4.9.7 (continued) more frequent REQUIREMENTS RCS temperature 80°F, 30 minute checks of the temperatures at the reactor vessel head flange and the shell adjacent to the head flange are required by SR 3.4.9.6 because of the reduced margin to the limits. When in MODE 4 with RCS temperature periodically 100°F, monitoring of the temperatures at the reactor vessel head flange and the shell adjacent to the head flange are required every 12 hours by SR 3.4.9.7 to ensure the temperatures are The Surveillance within the specified limits.
| |
| Frequencies are controlled under The 30 minute Frequency for SR 3.4.9.5 and SR 3.4.9.6 reflects the urgency of maintaining the temperatures within limits, and also the Surveillance limits the time that the temperature limits could be exceeded. The Frequency 12 hour Frequency for SR 3.4.9.7 is reasonable based on the rate Control Program. of temperature change possible at these temperatures.
| |
| SR 3.4.9.5 is modified by a Note that requires the Surveillance to be performed only when tensioning the reactor vessel head bolting studs. However, per SR 3.0.4, the Surveillance needs to the Surveillance be met prior to tensioning, i.e., verified within 30 minutes of the Frequency prior to start of tensioning. SR 3.4.9.6 is modified by a Note that requires the Surveillance to be initiated 30 minutes after RCS temperatures 80°F in Mode 4. SR 3.4.9.7 is modified by a Note that requires the Surveillance to be initiated 12 hours after RCS temperature 100°F in Mode 4. The Notes contained in these SRs are necessary to specify when the reactor vessel flange and head flange temperatures are required to be verified to be within the limits specified.
| |
| (continued) 120 DAEC B 3.4-57 TSCR-017
| |
| | |
| Reactor Steam Dome Pressure B 3.4.10 BASES APPLICABILITY In MODES 4, and 5, the reactor pressure is well below the (continued) required limit due to the pressure and temperature limits of these MODES, and no anticipated events will challenge either the fuel thermal limits or the vessel overpressure limit.
| |
| ACTIONS A.1 With the reactor steam dome pressure greater than the limit, prompt action should be taken to reduce pressure to below the limit and return the reactor to operation within the bounds of the analyses. The 15 minute Completion Time is reasonable considering the importance of maintaining the pressure within limits. This Completion Time also ensures that the probability of an accident occurring while pressure is greater than the limit is minimized.
| |
| B.1 If the reactor steam dome pressure cannot be restored to within the limit within the associated Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. The allowed Completion Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.
| |
| SURVEILLANCE SR 3.4.10.1 REQUIREMENTS The Surveillance Verification that reactor steam dome pressure is 1025 psig Frequency is controlled ensures that the initial conditions of the accident and transient under the Surveillance analyses are met. Operating experience has shown the 12 hour Frequency Control Frequency to be sufficient for identifying trends and verifying operation within safety analyses assumptions.
| |
| Program.
| |
| (continued) 120 DAEC B 3.4-60 TSCR-097
| |
| | |
| ECCS Operating B 3.5.1 BASES ACTIONS M.1 and M.2 (continued)
| |
| If any Required Action and associated Completion Time of Condition K or L is not met, or if two or more ADS valves are inoperable, the plant must be brought to a condition in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and reactor steam dome pressure reduced to 100 psig within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
| |
| N.1 When multiple ECCS subsystems are inoperable, as stated in Condition N, the plant is in a condition outside of the accident analyses. Therefore, LCO 3.0.3 must be entered immediately.
| |
| SURVEILLANCE SR 3.5.1.1 REQUIREMENTS The flow path piping has the potential to develop bubbles and pockets of entrained air. Maintaining the pump discharge line of the HPCI system, CS system, and LPCI subsystems full of water (up to the normally closed injection valve) ensures that the ECCS will perform properly, injecting its full capacity into the RCS upon demand. This will also prevent a potential water hammer following an ECCS initiation signal. An acceptable method of ensuring that the CS or LPCI discharge lines are full is to vent at the respective high points. Another acceptable method for CS and LPCI is to verify the absence of their respective discharge line Low Pressure Annuciator alarms. Acceptable methods for HPCI The Surveillance are the combination of venting at high points and, either ensuring Frequency is controlled adequate CST water level or that the HPCI Low Pressure Keep under the Surveillance Fill is in service. The 31 day frequency is based on the gradual Frequency Control nature of bubble buildup in the ECCS piping, the procedural controls governing system operation and operating experience.
| |
| Program.
| |
| (continued) 120 DAEC B 3.5-13 TSCR-112
| |
| | |
| ECCS Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.2 REQUIREMENTS (continued) Verifying the correct alignment for power operated and automatic valves in the ECCS flow paths provides assurance that the proper flow paths will exist for ECCS operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these were verified to be in the correct position prior to locking, sealing, or securing. A valve that receives an initiation signal is allowed to be in a nonaccident position provided the valve will automatically reposition in the proper stroke time. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of potentially being mispositioned are in the correct position. This SR does not apply The Surveillance to manual valves or valves that cannot be inadvertently Frequency is controlled misaligned, such as check valves. For the HPCI System, this SR also includes the steam flow path for the turbine and the flow under the Surveillance controller position.
| |
| Frequency Control Program. The 31 day Frequency of this SR was derived from the Inservice Testing Program requirements for performing valve testing at least once every 92 days. The Frequency of 31 days is further justified because the valves are operated under procedural control and because improper valve position would only affect a single subsystem. This Frequency has been shown to be acceptable through operating experience.
| |
| In Mode 3 with reactor steam dome pressure less than the actual RHR interlock pressure, the RHR System may be required to operate in the shutdown cooling mode to remove decay heat and sensible heat from the reactor. Therefore, this SR is modified by Note 1, which allows the LPCI System to be considered OPERABLE during alignment and operation for decay heat removal, if capable of being manually realigned (remote or local) to the LPCI mode and not otherwise inoperable. Alignment and operation for decay heat removal includes when the required RHR pump is not operating or when the system is realigned from or to the RHR shutdown cooling mode. At the low pressures and decay heat loads associated with operation in Mode 3 with reactor steam dome pressure less than the RHR interlock pressure, a reduced complement of low pressure ECCS subsystems should provide the required core cooling, thereby allowing operation of RHR shutdown cooling, when necessary.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.5-14 Amendment 223
| |
| | |
| ECCS Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.3 REQUIREMENTS (continued)
| |
| Verification every 31 days that a 100 day supply of nitrogen exists for each ADS accumulator ensures adequate nitrogen pressure for reliable ADS operation. The accumulator on each ADS valve provides pneumatic pressure for valve actuation. The design pneumatic supply pressure requirements for the accumulator are such that following a failure of the pneumatic supply to the accumulator, each ADS valve can be actuated at least 5 times up to 100 days following a LOCA (Reference 4). This SR can be met by either: 1) verifying that the drywell nitrogen header supply pressure is 90 psig, or 2) when drywell nitrogen header supply pressure is < 90 psig, using the actual accumulator check valve leakage rates obtained from the most-recent tests to determine, analytically, that a 100 day supply of nitrogen exists for each accumulator. The results of this analysis can also be used to The Surveillance determine when the 100 day supply of nitrogen will no longer exist Frequency is controlled for individual ADS accumulators, and when each ADS valve would under the Surveillance subsequently be required to be declared inoperable, assuming the Frequency Control drywell nitrogen supply pressure is not restored to 90 psig. The 31 day Frequency takes into consideration administrative controls Program. over operation of the nitrogen system and alarms for low nitrogen pressure.
| |
| SR 3.5.1.4, SR 3.5.1.5, and SR 3.5.1.6 The performance requirements of the low pressure ECCS pumps are determined through application of the 10 CFR 50, Appendix K criteria (Ref. 8). This periodic Surveillance is performed (in accordance with the ASME Code, Section XI, requirements for the ECCS pumps) to verify that the ECCS pumps will develop the flow rates required by the respective analyses. The low pressure ECCS pump flow rates ensure that adequate core cooling is provided to satisfy the acceptance criteria of Reference 10. The pump flow rates are verified against a system head equivalent to the RPV pressure expected during a LOCA. The total system pump outlet pressure is adequate to overcome the elevation head pressure between the pump suction and the vessel discharge, the piping friction losses, and RPV pressure present during a LOCA.
| |
| These values may be established during preoperational testing or by analysis.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.5-15 Amendment 223
| |
| | |
| ECCS Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.4, SR 3.5.1.5, and SR 3.5.1.6 (continued)
| |
| REQUIREMENTS The flow tests for the HPCI System are performed at two different pressure ranges such that system capability to provide rated flow is tested at both the higher and lower operating ranges of the system. Additionally, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the HPCI System diverts steam flow. Reactor steam pressure must be 940 psig to perform SR 3.5.1.5, the high pressure test, and 160 psig to perform SR 3.5.1.6, the low pressure test. Adequate steam flow is represented by approximately 0.5 turbine bypass valves open.
| |
| Therefore, sufficient time is allowed after adequate pressure and flow are achieved to perform these tests. Reactor startup is allowed prior to performing the low pressure Surveillance test because the reactor pressure is low and the time allowed to satisfactorily perform the Surveillance test is short. The reactor pressure is allowed to be increased to normal operating pressure since it is assumed that the low pressure test has been satisfactorily completed and there is no indication or reason to believe that HPCI is inoperable.
| |
| Therefore, SR 3.5.1.5 and SR 3.5.1.6 are modified by Notes that state the Surveillances are not required to be performed until 12 hours after the reactor steam pressure and flow are adequate to perform the test. The 12 hour allowance to reach the required pressure and flow is sufficient to achieve stable conditions for testing and provide a reasonable time to complete the SRs.
| |
| The Surveillance Frequency for SR 3.5.1.6 The Frequency for SR 3.5.1.4 and SR 3.5.1.5 is in accordance is controlled under the with the Inservice Testing Program requirements. The 24 month Surveillance Frequency Frequency for SR 3.5.1.6 is based on the need to perform the Control Program. Surveillance under the conditions that apply just prior to or during a startup from a plant outage. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle.
| |
| this Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.5-16 Amendment 223
| |
| | |
| ECCS Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.7 REQUIREMENTS (continued) The ECCS subsystems are required to actuate automatically to perform their design functions. This Surveillance verifies that, with a required system initiation signal (actual or simulated), the automatic initiation logic of HPCI, CS, and LPCI will cause the systems or subsystems to operate as designed, including actuation of the system throughout its emergency operating sequence, automatic pump startup and actuation of all automatic valves to their required positions. As part of this SR for the LPCI system, a verification of the "power-seeking" logic for the LPCI "Swing Bus" (1B34A and 1B44A), i.e., the ability to transfer power sources from either AC Essential Bus upon loss of power (either AC or 125 VDC), is included. This verification, when coupled with the verification of the "break-before-make" coordination of the breakers in SR 3.8.7.2, demonstrate the ability of the Swing Bus to perform its intended safety function in support of the Loop Select design of the LPCI system without compromising the independence of the AC Distribution System (Reference 16). This SR also ensures that the HPCI System will automatically restart on an RPV low water level signal received subsequent to an RPV high water level trip and that the suction is automatically transferred from the CST to the suppression pool on a CST Low Water Level Signal or Torus High Water Level Signal. The LOGIC The Surveillance SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1 overlaps Frequency is controlled this Surveillance to provide complete testing of the assumed under the Surveillance safety function.
| |
| Frequency Control Operating experience has shown that these components usually Program. pass the SR when performed at the 24 month Frequency, which is this based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| This SR is modified by two Notes. The first Note excludes vessel injection/spray during the Surveillance. Since all active components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the Surveillance. The second Note is added to SR 3.5.1.7 to allow the surveillance to be met by performing the test in any number of sequential and/or overlapping steps, rather than in a single, contiguous performance.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.5-17 Amendment 223
| |
| | |
| ECCS Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.7 (continued)
| |
| REQUIREMENTS This is necessary because testing the entire LPCI Loop Select Logic would interfere with forced reactor coolant circulation and/or decay heat removal functions and require multiple LPCI System starts to demonstrate all the Loop Select Logic features (e.g.,
| |
| injections paths, single loop operation and "swing" bus).
| |
| Therefore, each of the required features can be tested either individually or in appropriate combinations (including overlap with other LCO 3.5.1 surveillances, the Instrumentation surveillances required by LCO 3.3.5.1 and the "swing" bus breaker coordination surveillance in LCO 3.8.7), such that the overall function is tested on the required Frequency.
| |
| SR 3.5.1.8 The ADS designated SRVs are required to actuate automatically upon receipt of specific initiation signals. A system functional test is performed to demonstrate that the mechanical portions of the ADS function (i.e., solenoids) operate as designed when initiated either by an actual or simulated initiation signal, causing proper actuation of all the required components. SR 3.5.1.9 and the The Surveillance LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1 Frequency is controlled overlap this Surveillance to provide complete testing of the under the Surveillance assumed safety function.
| |
| Frequency Control The 24 month Frequency is based on the need to perform the Program. Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the this refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| This SR is modified by a Note that excludes valve actuation, since the valves are individually tested in accordance with SR 3.5.1.9.
| |
| This prevents an RPV pressure blowdown.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.5-18 Amendment 223
| |
| | |
| ECCS Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.9 REQUIREMENTS (continued) A manual actuation of each ADS valve is performed to verify that the valve and solenoid are functioning properly and that no blockage exists in the SRV discharge lines. This is demonstrated by the response of the turbine control or bypass valve or by a change in the measured flow or by any other method suitable to verify steam flow (such as actuation of the SRV tailpipe pressure switches or thermocouples). Adequate reactor steam dome pressure must be available to perform this test to avoid damaging the valve. Also, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the ADS valves divert steam flow upon opening. Sufficient time is therefore allowed after the required pressure and flow are achieved to perform this SR. Adequate pressure at which this SR is to be performed is approximately 150 psig which is the lowest pressure EHC can maintain. Adequate steam flow is represented by approximately 1.15 turbine bypass valves open. Reactor startup is allowed prior to performing this SR because valve OPERABILITY and the setpoints for overpressure protection are verified, per ASME requirements, prior to valve installation. Therefore, this SR is modified by a Note that states the Surveillance is not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test. The 12 hours allowed for manual actuation after the required pressure and flow is reached is sufficient to achieve stable The Surveillance conditions and provides adequate time to complete the Frequency is controlled Surveillance. SR 3.5.1.8 and the LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1 overlap this Surveillance to under the Surveillance provide complete testing of the assumed safety function.
| |
| Frequency Control Program. The Frequency of 24 months is based on the need to perform the Surveillance under the conditions that apply just prior to or during a startup from a plant outage. Operating experience has shown that these components usually pass the SR when performed at this the 24 month Frequency, which is based on the refueling cycle.
| |
| Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.5-19 Amendment 223
| |
| | |
| ECCS Shutdown B 3.5.2 BASES SURVEILLANCE SR 3.5.2.1 and SR 3.5.2.2 (continued)
| |
| REQUIREMENTS When suppression pool level is < 8.0 ft, the CS System is considered OPERABLE only if it can take suction from the CST, and the CST water level is sufficient to provide the required NPSH for the CS pump. Therefore, a verification that either the suppression pool water level is 8.0 ft or that CS is aligned to take suction from the CSTs and the CSTs contain 75,000 gallons of water, equivalent to 11 ft in one CST or 7 ft in both CSTs, ensures that the CS System can supply at least 75,000 gallons of makeup water to the RPV. However, as noted, only one required CS subsystem may take credit for the CST option during OPDRVs. During OPDRVs, the volume in the CST may not provide adequate makeup if the RPV were completely The Surveillance drained. Therefore, only one CS subsystem is allowed to use the CST. This ensures the other required ECCS subsystem has Frequency is controlled adequate makeup volume.
| |
| under the Surveillance Frequency Control The 12 hour Frequency of these SRs was developed considering Program. operating experience related to suppression pool water level and CST water level variations during the applicable MODES.
| |
| Furthermore, the 12 hour Frequency is considered adequate in view of other indications available in the control room to alert the operator to an abnormal suppression pool or CST water level condition.
| |
| SR 3.5.2.3, SR 3.5.2.5, and SR 3.5.2.6 The Bases provided for SR 3.5.1.1, SR 3.5.1.4, and SR 3.5.1.7 are applicable to SR 3.5.2.3, SR 3.5.2.5, and SR 3.5.2.6, respectively.
| |
| SR 3.5.2.4 Verifying the correct alignment for power operated and automatic valves in the ECCS flow paths provides assurance that the proper flow paths will exist for ECCS operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve that receives an initiation signal is allowed to be in a nonaccident position provided the (continued)
| |
| TSCR-120 DAEC B 3.5-25 Amendment 223
| |
| | |
| ECCS Shutdown B 3.5.2 BASES SURVEILLANCE SR 3.5.2.4 (continued)
| |
| REQUIREMENTS valve will automatically reposition in the proper stroke time. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of potentially being The Surveillance mispositioned are in the correct position. This SR does not apply Frequency is controlled to manual valves or to valves that cannot be inadvertently under the Surveillance misaligned, such as check valves. The 31 day Frequency is appropriate because the valves are operated under procedural Frequency Control control and the probability of their being mispositioned during this Program. time period is low.
| |
| In Modes 4 and 5, the RHR System may be required to operate in the shutdown cooling mode to remove decay heat and sensible heat from the reactor. Therefore, this SR is modified by a Note that allows one LPCI subsystem to be considered OPERABLE during alignment and operation for decay heat removal, if capable of being manually realigned (remote or local) to the LPCI mode and not otherwise inoperable. Alignment and operation for decay heat removal includes when the required RHR pump is not operating or when the system is realigned from or to the RHR shutdown cooling mode. Because of the low pressure and low temperature conditions in Modes 4 and 5, sufficient time will be available to manually align and initiate LPCI subsystem operation to provide core coverage prior to postulated fuel uncovery. This will ensure adequate core cooling if an inadvertent RPV draindown should occur.
| |
| REFERENCES 1. UFSAR, Section 15.2.1.1.
| |
| 120 DAEC B 3.5-26 TSCR-044A
| |
| | |
| RCIC System B 3.5.3 BASES ACTIONS B.1 and B.2 (continued)
| |
| If the RCIC System cannot be restored to OPERABLE status within the associated Completion Time, or if the HPCI System is simultaneously inoperable, the plant must be brought to a condition in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and reactor steam dome pressure reduced to 150 psig within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
| |
| SURVEILLANCE SR 3.5.3.1 REQUIREMENTS The flow path piping has the potential to develop bubbles and pockets of entrained air. Maintaining the pump discharge line of the RCIC system full of water ensures that the system will perform properly, injecting its full capacity into the RCS upon demand.
| |
| This will also prevent a potential water hammer following an The Surveillance initiation signal. One acceptable method of ensuring that the lines Frequency is controlled are full is to vent at the high points with RCIC suction aligned to under the Surveillance the CST. The 31 day frequency is based on the gradual nature of Frequency Control bubble buildup in the RCIC piping, the procedural controls governing system operation and operating experience.
| |
| Program.
| |
| SR 3.5.3.2 Verifying the correct alignment for power operated and automatic valves in the RCIC flow path provides assurance that the proper flow path will exist for RCIC operation. A valve that receives an initiation signal is allowed to be in a nonaccident position provided the valve will automatically reposition in the proper stroke time.
| |
| This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of potentially being mispositioned are in the correct position. This SR does not apply to manual valves or to valves that cannot be inadvertently misaligned, such as check valves. For the RCIC System, this SR also includes the steam flow path for the turbine and the flow controller position.
| |
| (continued) 120 DAEC B 3.5-30 TSCR-089
| |
| | |
| RCIC System B 3.5.3 BASES SURVEILLANCE SR 3.5.3.2 (continued)
| |
| REQUIREMENTS The 31 day Frequency of this SR was derived from the Inservice The Surveillance Testing Program requirements for performing valve testing at least Frequency is controlled once every 92 days. The Frequency of 31 days is further justified under the Surveillance because the valves are operated under procedural control and Frequency Control because improper valve position would affect only the RCIC Program. System. This Frequency has been shown to be acceptable through operating experience.
| |
| SR 3.5.3.3 and SR 3.5.3.4 The RCIC pump flow rates ensure that the system can maintain reactor coolant inventory during pressurized conditions with the RPV isolated. The flow tests for the RCIC System are performed at two different pressure ranges such that system capability to provide rated flow is tested both at the higher and lower operating ranges of the system. Additionally, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the RCIC System diverts steam flow. Reactor steam pressure must be 940 psig to perform SR 3.5.3.3, the high pressure test, and 160 psig to perform SR 3.5.3.4, the low pressure test. Adequate steam flow is represented by approximately 0.4 turbine bypass valves open.
| |
| Therefore, sufficient time is allowed after adequate pressure and flow are achieved to perform these SRs. Reactor startup is allowed prior to performing the low pressure Surveillance because the reactor pressure is low and the time allowed to satisfactorily perform the Surveillance is short. The reactor pressure is allowed to be increased to normal operating pressure since it is assumed that the low pressure Surveillance has been satisfactorily completed and there is no indication or reason to believe that RCIC is inoperable.
| |
| Therefore, these SRs are modified by Notes that state the Surveillances are not required to be performed until 12 hours after the reactor steam pressure and flow are adequate to perform the test. The 12 hour allowance to reach the required pressure and flow is sufficient to achieve stable conditions for testing and provide a reasonable time to complete the SRs.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.5-31 Amendment 223
| |
| | |
| RCIC System in accordance with the B 3.5.3 Inservice Testing Program BASES SURVEILLANCE SR 3.5.3.3 and SR 3.5.3.4 (continued)
| |
| REQUIREMENTS The Surveillance Frequency for SR The Inservice Testing Program Frequency for SR 3.5.3.3 is every 3.5.3.4 is controlled under the 92 days. The 24 month Frequency for SR 3.5.3.4 is based on the Surveillance Frequency Control need to perform the Surveillance under conditions that apply just Program. prior to or during a startup from a plant outage. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based this on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| SR 3.5.3.5 The RCIC System is required to actuate automatically in order to verify its design function satisfactorily. This Surveillance verifies that, with a required system initiation signal (actual or simulated),
| |
| the automatic initiation logic of the RCIC System will cause the system to operate as designed, including actuation of the system throughout its emergency operating sequence; that is, automatic pump startup and actuation of all automatic valves to their required positions. This test also ensures the RCIC System will automatically restart on an RPV low water level signal received subsequent to an RPV high water level trip and that the suction is automatically transferred from the CST to the suppression pool on The Surveillance a CST Low Level signal. The LOGIC SYSTEM FUNCTIONAL Frequency is controlled TEST performed in LCO 3.3.5.2 overlaps this Surveillance to under the Surveillance provide complete testing of the assumed design function.
| |
| Frequency Control Program. The 24 month Frequency is based on the need to perform the Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the SR when this performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| This SR is modified by a Note that excludes vessel injection during the Surveillance. Since all active components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the Surveillance.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.5-32 Amendment 223
| |
| | |
| Primary Containment B 3.6.1.1 BASES SURVEILLANCE SR 3.6.1.1.2 (continued)
| |
| REQUIREMENTS drywell to suppression chamber differential pressure during a 10 minute period to measure and ensure that the leakage paths that would bypass the suppression pool are within allowable limits.
| |
| Satisfactory performance of this SR can be achieved by The Surveillance establishing a known differential pressure between the drywell Frequency is controlled and the suppression chamber and verifying that the increase in under the Surveillance suppression chamber pressure is less than 0.009 psi per minute Frequency Control when averaged over a 10 minute period. The leakage test is performed every 24 months. The 24 month Frequency was Program. developed considering it is required that this Surveillance be performed during a unit outage and also in view of the fact that component failures that might have affected this test are identified by other primary containment SRs.
| |
| REFERENCES 1. UFSAR, Section 6.2.
| |
| : 2. UFSAR, Section 15.2.
| |
| : 3. 10 CFR 50, Appendix J, Option B.
| |
| : 4. NEI 94-01, Revision 0, "Industry Guideline for Implementing Performance - Based Option of 10 CFR Part 50, Appendix J."
| |
| : 5. ANSI/ANS-56.8-1994, "American National Standard for Containment System Leakage Testing Requirement."
| |
| 120 DAEC B 3.6-5 TSCR-044A
| |
| | |
| Primary Containment Air Lock B 3.6.1.2 BASES SURVEILLANCE SR 3.6.1.2.2 REQUIREMENTS (continued) The air lock interlock mechanism is designed to prevent simultaneous opening of both doors in the air lock. Since both the inner and outer doors of an air lock are designed to withstand the maximum expected post accident primary containment pressure, closure of either door will support primary containment OPERABILITY. Thus, the interlock feature supports primary containment OPERABILITY while the air lock is being used for personnel transit in and out of the containment. Periodic testing The Surveillance of this interlock demonstrates that the interlock will function as Frequency is controlled designed and that simultaneous inner and outer door opening will under the Surveillance not inadvertently occur. Due to the purely mechanical nature of Frequency Control this interlock, and given that the interlock mechanism is not normally challenged when the primary containment airlock door is Program.
| |
| used for entry and exit (procedures require strict adherence to single door opening), this test is only required to be performed every 24 months. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage, and the potential for loss of primary containment OPERABILITY if the Surveillance were performed with the reactor at power. The 24 month Frequency for the interlock is justified based on generic operating experience. The Frequency is based on engineering judgment and is considered adequate given that the interlock is not challenged during use of the airlock.
| |
| REFERENCES 1. UFSAR, Section 6.2.1.1.
| |
| : 2. 10 CFR 50, Appendix J, Option B.
| |
| : 3. UFSAR, Section 15.2.1.
| |
| 120 DAEC B 3.6-13 TSCR-044A
| |
| | |
| PCIVs B 3.6.1.3 BASES SUREVEILLANCE SR 3.6.1.3.1 (continued)
| |
| REQUIREMENTS The 31 day Frequency was chosen to provide added assurance The Surveillance that the purge valves are in the correct position.
| |
| Frequency is controlled under the Surveillance SR 3.6.1.3.2 Frequency Control Program. The traversing incore probe (TIP) shear isolation valves are actuated by explosive charges. Surveillance of explosive charge continuity provides assurance that TIP valves will actuate The Surveillance Frequency is when required. Other administrative controls, such as those that controlled under the limit the shelf life of the explosive charges, must be followed. The Surveillance Frequency Control 31 day Frequency is based on operating experience that has Program. demonstrated the reliability of the explosive charge continuity.
| |
| SR 3.6.1.3.3 Verifying the isolation time of each power operated automatic PCIV is within limits is required to demonstrate OPERABILITY.
| |
| MSIVs may be excluded from this SR since MSIV full closure isolation time is demonstrated by SR 3.6.1.3.5. The isolation time test ensures that the valve will isolate in a time period less than or equal to that assumed in the safety analyses. The isolation time and Frequency of this SR are in accordance with the requirements of the Inservice Testing Program.
| |
| SR 3.6.1.3.4 For primary containment purge valves with resilient seals, additional leakage rate testing beyond the test requirements of corresponding 10 CFR 50, Appendix J, Option B (Ref. 3), is required to ensure Surveillance OPERABILITY. Operating experience has demonstrated that this type of seal has the potential to degrade in a shorter time period than do other seal types. Based on this observation and the The Surveillance importance of maintaining this penetration leak tight (due to the Frequency is controlled direct path between primary containment and the environment), a under the Surveillance Frequency of 184 days was established. The purge system Frequency Control isolation valves are tested in three groups, by penetration: drywell purge exhaust group (CV-4302 and CV-4303), torus purge Program.
| |
| exhaust group (CV-4300 and CV-4301), and drywell/torus purge supply group (CV-4307, CV-4308 and CV-4306). If the results of a combined leak rate or pressure drop test indicate excessive leakage, credit can be taken for one of the purge valves to (continued) 120 DAEC B 3.6-26 TSCR-025
| |
| | |
| PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.4 (continued)
| |
| REQUIREMENTS satisfy Required Action E.1, if it can be reasonably determined that the purge valve to be credited for isolation is not leaking excessively.
| |
| Additionally, this SR must be performed once within 92 days after opening the valve. The 92 day Frequency was chosen recognizing that cycling the valve could introduce additional seal degradation (beyond that which occurs to a valve that has not normal Surveillance been opened.) Thus, decreasing the interval (from 184 days) is a prudent measure after a valve has been opened.
| |
| SR 3.6.1.3.5 Verifying that the isolation time of each MSIV is within the specified limits is required to demonstrate OPERABILITY. The isolation time test ensures that the MSIV will isolate in a time period that does not exceed the times assumed in the DBA analyses. This ensures that the calculated radiological consequences of these events remain within 10 CFR 50.67 limits and that the core remains covered. The Frequency of this SR is in accordance with the requirements of the Inservice Testing Program.
| |
| SR 3.6.1.3.6 Automatic PCIVs close on a primary containment isolation signal to prevent leakage of radioactive material from primary containment following a DBA. This SR ensures that each automatic PCIV will actuate to its isolation position on a primary containment isolation signal. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.6.1, "Primary Containment Isolation Instrumentation," overlaps this SR to provide complete testing of the safety function. A Note has been added for the MSIVs, that The Surveillance allows this SR to be met by any series of sequential, overlapping, Frequency is controlled or total steps so that proper operation of the MSIVs on receipt of under the Surveillance an actual or simulated isolation signal is verified. The 24 month Frequency Control Frequency was developed considering it is prudent that this Surveillance be performed only during a unit outage since Program.
| |
| isolation of penetrations would eliminate cooling water flow and disrupt the normal operation of many critical components.
| |
| Operating experience has shown that these components usually pass this Surveillance when performed at the 24 month this (continued) 120 DAEC B 3.6-27 TSCR-044A
| |
| | |
| PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.6 (continued)
| |
| REQUIREMENTS (continued) Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| SR 3.6.1.3.7 This SR requires a demonstration that a representative sample of reactor instrumentation line Excess Flow Check Valves (EFCVs) are OPERABLE by verifying that the valves cause a marked decrease in flow rate on a simulated instrument line break. This SR provides assurance that the instrumentation line EFCVs will perform so that predicted radiological consequences will not be exceeded during the postulated instrument line break event evaluated in Reference 5. The representative sample consists of an approximately equal number of EFCVs, such that each EFCV is tested at least once every 10 years (nominal). The nominal 10 year interval is based on other performance-based testing programs, such as Inservice Testing (snubbers) and Option B to The Surveillance 10 CFR 50, Appendix J. EFCV test failures will be evaluated to Frequency is controlled determine if additional testing in that test interval is warranted to under the Surveillance ensure overall reliability is maintained. Operating experience has Frequency Control demonstrated that these components are highly reliable and that failures to isolate are very infrequent. Therefore, testing of a Program.
| |
| representative sample was concluded to be acceptable from a reliability standpoint (Reference 10).
| |
| SR 3.6.1.3.8 The TIP shear isolation valves are actuated by explosive charges.
| |
| An in place functional test is not possible with this design. The explosive squib is removed and tested to provide assurance that the valves will actuate when required. The replacement charge for the explosive squib shall be from the same manufactured batch as the one fired or from another batch that has been certified by having one of the batch successfully fired. Other administrative controls, such as those that limit the shelf life of the explosive charges, must also be followed. The Frequency of this SR is in accordance with the requirements of the Inservice Testing Program.
| |
| (continued) 120 DAEC B 3.6-28 TSCR-010
| |
| | |
| Drywell Air Temperature B 3.6.1.4 BASES (continued)
| |
| SURVEILLANCE SR 3.6.1.4.1 REQUIREMENTS Verifying that the drywell average air temperature is within the LCO limit ensures that operation remains within the limits assumed for the primary containment analyses. Drywell air The Surveillance temperature is monitored in all quadrants and at various elevations (referenced to mean sea level). Due to the shape of Frequency is controlled the drywell, a volumetric average is used to determine an under the Surveillance accurate representation of the actual average temperature.
| |
| Frequency Control Program. The 24 hour Frequency of the SR was developed based on operating experience related to drywell average air temperature variations and temperature instrument drift during the applicable MODES and the low probability of a DBA occurring between surveillances. Furthermore, the 24 hour Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal drywell air temperature condition.
| |
| REFERENCES 1. USAR, Section 15.0.
| |
| : 2. UFSAR, Section 15.2.1.
| |
| 120 DAEC B 3.6-32 TSCR-044A
| |
| | |
| LLS Valves B 3.6.1.5 BASES ACTIONS B.1 and B.2 (continued)
| |
| If both LLS valves are inoperable or if the inoperable LLS valve cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
| |
| SURVEILLANCE SR 3.6.1.5.1 REQUIREMENTS A manual actuation of each LLS valve is performed to verify that the valve and solenoids are functioning properly and no blockage exists in the valve discharge line. This can be demonstrated by the response of the turbine control or bypass valve, by a change in the measured steam flow, or by any other method that is suitable to verify steam flow. Adequate reactor steam dome pressure must be available to perform this test to avoid damaging the valve. Adequate pressure at which this test is to be performed is approximately 150 psig which is the lowest pressure EHC can maintain. Also, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control The Surveillance reactor pressure when the LLS valves divert steam flow upon Frequency is controlled opening. Adequate steam flow is represented by approximately under the Surveillance 1.15 turbine bypass valves open. The 24 month Frequency was based on the SRV tests required by the ASME Boiler and Frequency Control Pressure Vessel Code, Section XI (Ref. 2). Operating experience Program. has shown that these components usually pass the Surveillance this when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| Since steam pressure is required to perform the Surveillance, however, and steam may not be available during a unit outage, the Surveillance may be performed during the startup following a unit outage. Unit startup is allowed (continued)
| |
| TSCR-120 DAEC B 3.6-35 Amendment 223
| |
| | |
| LLS Valves B 3.6.1.5 BASES SURVEILLANCE SR 3.6.1.5.1 (continued)
| |
| REQUIREMENTS prior to performing the test because valve OPERABILITY and the setpoints for overpressure protection are verified in accordance with Reference 2 prior to valve installation. After adequate reactor steam dome pressure and flow are reached, 12 hours is allowed to prepare for and perform the test.
| |
| SR 3.6.1.5.2 The LLS designated SRVs are required to actuate automatically upon receipt of specific initiation signals. A system functional test is performed to verify that the mechanical portions (i.e., solenoids) of the LLS function operate as designed when initiated either by The Surveillance an actual or simulated automatic initiation signal. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.6.3, "Low-Low Set Frequency is controlled (LLS) Instrumentation," overlaps this SR to provide complete under the Surveillance testing of the safety function.
| |
| Frequency Control Program. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when this performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| This SR is modified by a Note that excludes valve actuation. This prevents a reactor pressure vessel pressure blowdown.
| |
| REFERENCES 1. UFSAR, Section 5.4.13.
| |
| : 2. ASME, Boiler and Pressure Vessel Code, Section XI.
| |
| : 3. NEDE-30021-P, Low-Low Set Relief Logic System and Lower MSIV Water Level Trip for DAEC, January 1983.
| |
| TSCR-120 DAEC B 3.6-36 Amendment 223
| |
| | |
| Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.6 BASES SURVEILLANCE SR 3.6.1.6.1 (continued)
| |
| REQUIREMENTS The Surveillance Frequency breaker assembly valve be periodically verified to be closed by is controlled under the visual inspection. The 14 day Frequency is based on engineering Surveillance Frequency judgment, is considered adequate in view of other indications of Control Program. vacuum breaker assembly valve status available to operations personnel, and has been shown to be acceptable through operating experience.
| |
| Two Notes are added to this SR. The first Note allows reactor building-to-suppression chamber vacuum breaker assembly valves opened in conjunction with the performance of a Surveillance to not be considered as failing this SR. These periods of opening vacuum breaker assembly valves are controlled by plant procedures and do not represent inoperable vacuum breaker assembly valves. The second Note is included to clarify that vacuum breaker assembly valves open due to an actual differential pressure are not considered as failing this SR.
| |
| SR 3.6.1.6.2 Each vacuum breaker assembly valve must be cycled to ensure The Surveillance Frequency is that it opens properly to perform its design function and returns to controlled under the Surveillance its fully closed position. This ensures that the safety analysis assumptions are valid. The 92 day Frequency of this SR was Frequency Control Program.
| |
| developed based upon Inservice Testing Program requirements to for performing perform valve testing at least once every 92 days.
| |
| SR 3.6.1.6.3 Demonstration of vacuum breaker assembly valve opening The Surveillance setpoint is necessary to ensure that the safety analysis Frequency is controlled assumption regarding vacuum breaker assembly valve full open under the Surveillance differential pressure of 0.614 psid is valid. The 12 month Frequency Control Frequency is based upon the assumption of a 12 month Program. calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
| |
| REFERENCES 1. UFSAR, Section 6.2.1.1.2.5.
| |
| 120 DAEC B 3.6-42 TSCR-044A
| |
| | |
| Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.7 BASES ACTIONS C.1 and C.2 (continued) must be brought to at least MODE 3 within 12 hours and to MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
| |
| SURVEILLANCE SR 3.6.1.7.1 REQUIREMENTS Each vacuum breaker is verified closed (except when performing its intended function as stated in LCO 3.6.1.7) to ensure that this potential large bypass leakage path is not present. This Surveillance is performed by observing the vacuum breaker position indication or by verifying that a differential pressure of 0.5 psid between the suppression chamber and drywell is maintained for 1 hour without makeup. Each vacuum breaker is equipped with two closed position indicators. One position indicator indicating closed is sufficient to verify the vacuum The Surveillance breaker is closed. However, if one closed position indicator is Frequency is controlled found to be inoperable, actions should be initiated to restore it to under the Surveillance OPERABLE status, if possible. The 14 day Frequency is based Frequency Control on engineering judgment, is considered adequate in view of other indications of vacuum breaker status available to operations Program.
| |
| personnel, and has been shown to be acceptable through operating experience.
| |
| A Note is added to this SR which allows suppression chamber-to-drywell vacuum breakers opened in conjunction with the performance of a Surveillance to not be considered as failing this SR. These periods of opening vacuum breakers are controlled by plant procedures and do not represent inoperable vacuum breakers.
| |
| SR 3.6.1.7.2 Each required vacuum breaker must be cycled to ensure that it The Surveillance opens adequately to perform its design function and returns to the Frequency is controlled fully closed position. This ensures that the safety analysis under the Surveillance assumptions are valid. The 31 day Frequency of this SR was Frequency Control developed, based on Inservice Testing Program requirements Program.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.6-47 Amendment 223
| |
| | |
| Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.7 BASES SURVEILLANCE SR 3.6.1.7.2 (continued)
| |
| REQUIREMENTS for performing to perform valve testing at least once every 92 days. A 31 day The Frequency was chosen to provide additional assurance that the vacuum breakers are OPERABLE, since they are located in a harsh environment (the suppression chamber airspace).
| |
| SR 3.6.1.7.3 The Surveillance Verification of the vacuum breaker opening setting is necessary to Frequency is controlled ensure that the safety analysis assumption regarding vacuum under the Surveillance breaker full open differential pressure of 0.5 psid is valid. The Frequency Control 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage.
| |
| Program. The 24 month Frequency has been shown to be acceptable, based on operating experience, and is further justified because of other surveillances performed at shorter Frequencies that convey the proper functioning status of each vacuum breaker.
| |
| REFERENCES 1. UFSAR, Section 6.2.1.1.2.5.
| |
| : 2. UFSAR, Section 6.2.1.4.2.
| |
| 120 DAEC B 3.6-48 TSCR-044A
| |
| | |
| Suppression Pool Average Temperature B 3.6.2.1 BASES ACTIONS D.1, D.2, and D.3 (continued)
| |
| Given the high suppression pool average temperature in this Condition, the monitoring Frequency is increased to twice that of Condition A. Furthermore, the 30 minute Completion Time is considered adequate in view of other indications available in the control room to alert the operator to an abnormal suppression pool average temperature condition.
| |
| E.1 and E.2 If suppression pool average temperature cannot be maintained at 120°F, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the reactor pressure must be reduced to < 200 psig within 12 hours, and the plant must be brought to at least MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
| |
| Continued addition of heat to the suppression pool with suppression pool temperature > 120°F could result in exceeding the design basis maximum allowable values for primary containment temperature or pressure post-LOCA. Furthermore, if a blowdown were to occur when the temperature was > 120°F, the maximum allowable bulk suppression pool temperature could be exceeded very quickly and possibly exceed the allowable loads on the Torus.
| |
| SURVEILLANCE SR 3.6.2.1.1 REQUIREMENTS The suppression pool average temperature is regularly monitored The Surveillance to ensure that the required limits are satisfied. The average Frequency is controlled temperature is determined by taking an arithmetic average of under the Surveillance OPERABLE suppression pool water temperature channels. The 24 hour Frequency has been shown, based on operating Frequency Control experience, to be acceptable. When heat is being added to the Program. suppression pool by testing, however, it is necessary to monitor suppression pool temperature more frequently.
| |
| (continued) 120 DAEC B 3.6-53 TSCR-044
| |
| | |
| Suppression Pool Water Level B 3.6.2.2 BASES (continued)
| |
| ACTIONS A.1 With suppression pool water level outside the limits, the conditions assumed for the safety analyses are not met. If water level is below the minimum level, the pressure suppression function still exists as long as vent system downcomer pipes are covered, HPCI and RCIC turbine exhausts are covered, and SRV T-quenchers are covered. If suppression pool water level is above the maximum level, protection against overpressurization still exists due to the margin in the peak containment pressure analysis. Therefore, continued operation for a limited time is allowed. The 2 hour Completion Time is sufficient to restore suppression pool water level to within limits. Also, it takes into account the low probability of an event impacting the suppression pool water level occurring during this interval.
| |
| B.1 and B.2 If suppression pool water level cannot be restored to within limits within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
| |
| SURVEILLANCE SR 3.6.2.2.1 REQUIREMENTS The Surveillance Frequency is Verification of the suppression pool water level is to ensure that controlled under the the required limits are satisfied. The 24 hour Frequency of this Surveillance Frequency SR was developed considering operating experience related to Control Program. trending variations in suppression pool water level and water level instrument drift during the applicable MODES and to assessing the proximity to the specified LCO level limits. Furthermore, the 24 hour Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal suppression pool water level condition.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.6-57 Amendment 223
| |
| | |
| RHR Suppression Pool Cooling B 3.6.2.3 BASES (continued)
| |
| SURVEILLANCE SR 3.6.2.3.1 REQUIREMENTS Verifying by administrative means the correct alignment for manual, power operated and automatic valves in the RHR suppression pool cooling mode flow path provides assurance that the proper flow path exists for system operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking, sealing or securing. A valve is also allowed to be in the nonaccident position provided it can be aligned to the accident position within the time assumed in the accident analysis. This is acceptable since the RHR suppression pool cooling mode is manually initiated. This SR does not require any testing or valve manipulation; rather, it involves verification The Surveillance that those valves capable of being mispositioned are in the correct Frequency is controlled position. This SR does not apply to manual valves or to valves that cannot be inadvertently misaligned, such as check valves.
| |
| under the Surveillance Frequency Control The Frequency of 31 days is justified because the valves are Program. operated under procedural control, improper valve position would affect only a single subsystem, the probability of an event requiring initiation of the system is low, and the subsystem is a manually initiated system. This Frequency has been shown to be acceptable based on operating experience.
| |
| SR 3.6.2.3.2 Verifying that each RHR pump develops a flow rate 4800 gpm while operating in the suppression pool cooling mode with flow through the associated heat exchanger ensures that the primary containment peak pressure and temperature and the local suppression pool temperature can be maintained below design limits. This test also verifies that pump performance has not degraded during the surveillance interval. Flow is a normal test of centrifugal pump performance required by ASME Code, Section XI (Ref. 2). This test confirms one point on the pump design curve, and the results are indicative of overall performance. Such inservice testing confirms component OPERABILITY, trends performance, and detects incipient failures by indicating abnormal performance. The Frequency of this SR is in accordance with the Inservice Testing Program.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.6-63 Amendment 223
| |
| | |
| RHR Suppression Pool Spray B 3.6.2.4 BASES (continued)
| |
| SURVEILLANCE SR 3.6.2.4.1 REQUIREMENTS Verifying that the spray header and nozzles are unobstructed assures that the suppression pool airspace can be sprayed when desired. An air test is specified as this test is generally performed The Surveillance on both the drywell and suppression pool spray nozzles at the Frequency is controlled same time and it is not desirable to spray water into the drywell, under the Surveillance due to the adverse impact on equipment located there.
| |
| Frequency Control Program. Operating experience has shown that these components usually pass the SR when performed at the 60 month Frequency. this Therefore, the Frequency was concluded to be acceptable from the reliability standpoint.
| |
| REFERENCES 1. UFSAR, Section 15.2.1.
| |
| : 2. NG-98-0342, J. Franz (IES) to U.S. NRC, "Request for Technical Specification Change (RTS-291): Revision E to the Duane Arnold Energy Center Improved Technical Specifications," February 26, 1998.
| |
| 120 DAEC B 3.6-68 TSCR-044A
| |
| | |
| Primary Containment Oxygen Concentration B 3.6.3.2 BASES ACTIONS B.1 (continued)
| |
| If oxygen concentration cannot be restored to within limits within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, power must be reduced to 15% RTP within 8 hours. The 8 hour Completion Time is reasonable, based on operating experience, to reduce reactor power from full power conditions in an orderly manner and without challenging plant systems.
| |
| SURVEILLANCE SR 3.6.3.2.1 REQUIREMENTS The Surveillance Frequency The primary containment must be determined to be inert by is controlled under the verifying that oxygen concentration is < 4.0 v/o. The 7 day Surveillance Frequency Frequency is based on the slow rate at which oxygen Control Program. concentration can change and on other indications of abnormal conditions (control room alarms for containment high oxygen concentration, excessive cycling of the Containment Nitrogen Makeup System or unexplained changes in containment pressure). Indication of abnormal conditions would lead to more frequent monitoring of primary containment oxygen concentration.
| |
| Also, this Frequency has been shown to be acceptable through operating experience.
| |
| REFERENCES 1. Federal Register Notice 68 FR 54123, Combustible Gas Control in Containment, Final Rule, dated September 16, 2003.
| |
| (continued) 120 DAEC B 3.6-76 TSCR-083A
| |
| | |
| Secondary Containment B 3.6.4.1 BASES SURVEILLANCE SR 3.6.4.1.1 and SR 3.6.4.1.2 (continued)
| |
| REQUIREMENTS The Surveillance Frequency opening is being used for entry and exit or when maintenance is is controlled under the being performed on an access. The 31 day Frequency for these Surveillance Frequency SRs has been shown to be adequate, based on operating Control Program. experience, and is considered adequate in view of the other indications of door and hatch status that are available to the operator (alarmed security/secondary containment doors, frequent plant tours by operations and security personnel and unexplained drops in reactor building to outside atmosphere differential pressure while secondary containment is isolated with SBGT in service). SR 3.6.4.1.2 is modified by a Note that applies to doors located in high radiation areas and allows them to be verified by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted. Therefore, the probability of misalignment of these doors, once they have been verified to be in the proper position, is low.
| |
| SR 3.6.4.1.3 The SBGT System exhausts the secondary containment atmosphere to the environment through appropriate treatment equipment. SR 3.6.4.1.3 demonstrates that one SBGT subsystem can maintain 0.25 inches of vacuum water gauge under calm wind conditions (i.e., less than 15 mph wind speed) at a flow rate 4000 cfm. This cannot be accomplished if the secondary containment boundary is not intact. Therefore, this test is used to ensure secondary containment boundary integrity. Since this SR is a secondary containment test, it need not be performed with each SBGT subsystem. The SBGT subsystems are tested on a an alternating basis STAGGERED TEST BASIS, however, to ensure that in addition to the requirements of LCO 3.6.4.3, either SBGT subsystem will perform this test, and also to ensure that the secondary containment remains sufficiently leak tight, even with a worst case The Surveillance single failure present (i.e., a lockout relay failure that results in Frequency is controlled either all of the inboard or all of the outboard SCIV/Ds failing to under the Surveillance close). Operating experience has shown these components Frequency Control usually pass the Surveillance when performed at the 24 month this Frequency.
| |
| Program.
| |
| Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| (continued) 120 DAEC B 3.6-81 TSCR-037
| |
| | |
| SCIV/Ds B 3.6.4.2 BASES (continued)
| |
| ACTIONS C.1 and C.2 (continued)
| |
| The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
| |
| D.1 If any Required Action and associated Completion Time are not met, the plant must be placed in a condition in which the LCO does not apply. Actions must be immediately initiated to suspend OPDRVs in order to minimize the probability of a vessel draindown and the subsequent potential for fission product release. Actions must continue until OPDRVs are suspended.
| |
| LCO 3.0.3 is not applicable while in MODE 4 or 5 when OPDRVs can occur. Required Action D.1 has been modified by a Note stating that LCO 3.0.3 is not applicable.
| |
| SURVEILLANCE SR 3.6.4.2.1 REQUIREMENTS Verifying that the isolation time of each power operated automatic SCIV/D is within limits is required to demonstrate OPERABILITY.
| |
| The Surveillance The isolation time test ensures that the SCIV/D will isolate in a Frequency is controlled time period less than or equal to that assumed in the safety under the Surveillance analyses. The Frequency of this SR is 92 days.
| |
| Frequency Control Program. SR 3.6.4.2.2 Verifying that each automatic SCIV/D closes on a secondary containment isolation signal is required to prevent leakage of radioactive material from secondary containment following a DBA or which are released during certain operations when primary containment is not required to be OPERABLE or take place outside primary containment. This SR ensures that each automatic SCIV/D will actuate to the isolation position on a secondary containment isolation signal. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.6.2, "Secondary Containment The Surveillance Frequency Isolation Instrumentation," overlaps this SR to provide complete is controlled under the testing of the safety function. The 24 month Frequency is based Surveillance Frequency Control Program.
| |
| (continued) 120 DAEC B 3.6-88 TSCR-037
| |
| | |
| SCIV/Ds B 3.6.4.2 BASES SURVEILLANCE SR 3.6.4.2.2 (continued)
| |
| REQUIREMENTS on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month this Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| REFERENCES 1. UFSAR, Section 15.2.1.1.
| |
| 120 DAEC B 3.6-89 TSCR-044A
| |
| | |
| SBGT System B 3.6.4.3 BASES ACTIONS E.1 (continued)
| |
| When two SBGT subsystems are inoperable, if applicable, actions must Immediately be initiated to suspend OPDRVs in order to minimize the probability of a vessel draindown and subsequent potential for fission product release. Actions must continue until OPDRVs are suspended.
| |
| LCO 3.0.3 is not applicable in MODE 4 or 5 when OPDRVs can occur. Required Action E.1 has been modified by a Note stating that LCO 3.0.3 is not applicable.
| |
| SURVEILLANCE SR 3.6.4.3.1 REQUIREMENTS Operating each SBGT subsystem ensures that both subsystems are OPERABLE and that all associated controls are functioning properly. It also ensures that blockage or fan or motor failure, can Periodic be detected for corrective action. Operation with the heaters on (automatic heater cycling to maintain temperature) for 10 The Surveillance Frequency continuous hours every 31 days eliminates moisture on the is controlled under the adsorbers and HEPA filters. The 31 day Frequency is sufficient to Surveillance Frequency ensure potential moisture build-up does not impact the adsorption Control Program. and filtering function. The 31 day Frequency was also developed in consideration of the known reliability of fan motors and controls and the redundancy available in the system, however these components are not the most-limiting for overall system reliability at this SR Frequency. It is not necessary to run the system for the full 10 hours to demonstrate Operability following maintenance, if that maintenance did not affect the filters and charcoal beds.
| |
| SR 3.6.4.3.2 This SR verifies that the required SBGT filter testing is performed in accordance with Specification 5.5.7, Ventilation Filter Testing Program (VFTP). The VFTP includes testing HEPA filter performance, charcoal adsorber efficiency, system flow capability, and the physical properties of the activated charcoal (general use and following specific operations). Specific test frequencies and additional information are discussed in detail in the VFTP.
| |
| (continued) 120 DAEC B 3.6-94 TSCR-037
| |
| | |
| SBGT System B 3.6.4.3 BASES SURVEILLANCE SR 3.6.4.3.2 (continued)
| |
| REQUIREMENTS A Note has been added to this SR delaying the entry into associated Conditions and Required Actions for up to one hour.
| |
| This is necessary because, due to a cross-tie duct between the two SBGT subsystems, the flow path through the SBGT subsystem not being tested must be isolated, making it inoperable, to establish conditions necessary to ensure the tested SBGT subsystem meets the filter train differential pressure requirements of the VFTP. During the testing, the ability to draw a vacuum on Secondary Containment is maintained by the subsystem under test. One hour minimizes the amount of time the SBGT subsystem is inoperable while providing enough time to perform the required testing. Additionally, LCO 3.0.5 provides allowances for post-maintenance testing required to return a SBGT subsystem to Operable status. The allowance provided by the Note avoids potential entry into LCO 3.0.3 (Condition D) during required routine surveillances and during demonstration of Operability for a previously inoperable subsystem under LCO 3.0.5.
| |
| SR 3.6.4.3.3 The Surveillance This SR verifies that each SBGT subsystem starts on receipt of an Frequency is controlled actual or simulated initiation signal. While this Surveillance can under the Surveillance be performed with the reactor at power, operating experience has Frequency Control shown that these components usually pass the Surveillance when Program. this performed at the 24 month Frequency. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.6.2, "Secondary Containment Isolation Instrumentation," overlaps this SR to provide complete testing of the safety function. Therefore, the Frequency was found to be acceptable from a reliability standpoint.
| |
| SR 3.6.4.3.4 The Surveillance This SR verifies that the filter cooler bypass damper can be Frequency is controlled opened and the fan started. This ensures that the ventilation under the Surveillance mode of SBGT System operation is available. This Surveillance can be performed with the reactor at power and operating Frequency Control experience has shown that these components usually pass the Program. Surveillance when performed at the 24 month Frequency. this Therefore, the Frequency was found to be acceptable from a reliability standpoint.
| |
| (continued) 120 DAEC B 3.6-95 TSCR-037
| |
| | |
| RHRSW System B 3.7.1 BASES SURVEILLANCE SR 3.7.1.1 (continued)
| |
| REQUIREMENTS This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to manual valves or to valves that cannot be inadvertently misaligned, such as check valves. This SR is considered met for OPERABLE valves that are temporarily placed in a position other The Surveillance Frequency than the standby readiness position under appropriate is controlled under the administrative and procedural controls. The administrative and Surveillance Frequency procedural controls (such as positioning during a Surveillance Control Program. Test Procedure or operating in accordance with an approved Operating Instruction) ensure the Operators are cognizant of valve positions and ensure valves are promptly returned to the standby readiness position when the evolution is completed.
| |
| The 31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions.
| |
| REFERENCES 1. UFSAR, Section 9.2.3.2.
| |
| : 2. UFSAR, Section 6.2.1.3.
| |
| : 3. UFSAR, Chapter 15.
| |
| : 4. UFSAR, Section 15.2.1.
| |
| 120 DAEC B 3.7-6 TSCR-044A
| |
| | |
| RWS System and UHS B 3.7.2 BASES ACTIONS B.1 and B.2 (continued)
| |
| If the RWS subsystem cannot be restored to OPERABLE status within the associated Completion Time, or both RWS subsystems are inoperable, or the UHS is determined to be inoperable, the unit must be placed in a MODE in which the LCO does not apply.
| |
| To achieve this status, the unit must be placed in at least MODE 3 within 12 hours and in MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.
| |
| The Required Actions of Condition B are modified by a Note indicating that the Applicable Condition of LCO 3.4.7 "Residual Heat Removal (RHR) Shutdown Cooling System - Hot Shutdown,"
| |
| be entered and Required Actions taken if the inoperable RWS subsystem results in an inoperable RHR Shutdown Cooling subsystem. The Note also alerts the operator that RHR shutdown cooling will be inoperable when the Applicability of LCO 3.4.7 is met. This allows the operator to make provisions for an alternate method of decay heat removal for each inoperable RHR shutdown cooling subsystem, in accordance with the Required Actions of LCO 3.4.7. This is in accordance with LCO 3.0.6 and ensures proper actions are taken for these components.
| |
| SURVEILLANCE SR 3.7.2.1 REQUIREMENTS This SR verifies the river water level to be sufficient for the proper The Surveillance Frequency operation of the RWS pumps (net positive suction head and pump is controlled under the vortexing are considered in determining this limit). The 24 hour Surveillance Frequency Frequency is based on operating experience related to trending of Control Program. the parameter variations during the applicable MODES.
| |
| SR 3.7.2.2 Verification of the River Water temperature ensures that the heat The Surveillance Frequency removal capability of the RHRSW and ESW Systems are within is controlled under the the assumptions of the DBA analysis. The 24 hour Frequency is Surveillance Frequency based on operating experience related to trending of the Control Program. parameter variations during the applicable MODES.
| |
| (continued) 120 DAEC B 3.7-10 TSCR-095
| |
| | |
| RWS System and UHS B 3.7.2 BASES SURVEILLANCE SR 3.7.2.3 REQUIREMENTS (continued) This SR verifies the river depth to provide sufficient flow to meet the plants emergency cooling requirements. River depth is measured in front of the Intake Structure. This SR is modified by The Surveillance Frequency a note which allows this SR not to be performed when river depth is controlled under the is 2 feet. If river depth falls below 2 feet, this SR is performed Surveillance Frequency once every 7 days to assure UHS OPERABILITY. The 7 day Control Program. frequency will ensure that river bed conditions are monitored until corrective actions, such as dredging, are implemented.
| |
| periodically until the river depth increase to at least 2 SR 3.7.2.4 feet.
| |
| Verifying the correct alignment for each power operated and automatic valve in each RWS subsystem flow path provides assurance that the proper flow paths will exist for RWS operation.
| |
| This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve is also allowed to be in the nonaccident position, and yet considered in the correct position, provided it can be automatically realigned to its accident position within the required time. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being The Surveillance Frequency mispositioned are in the correct position. This SR does not apply is controlled under the to manual valves or to valves that cannot be inadvertently Surveillance Frequency misaligned, such as check valves.
| |
| Control Program.
| |
| The 31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions.
| |
| SR 3.7.2.5 This SR verifies the river depth to provide sufficient flow to meet The Surveillance Frequency the plants emergency cooling requirements. River depth is is controlled under the measured in front of the Intake Structure. The 92 days Frequency Surveillance Frequency is based on operating experience related to trending of river Control Program. bottom fluctuations.
| |
| (continued) 120 DAEC B 3.7-11 TSCR-095
| |
| | |
| RWS System and UHS B 3.7.2 BASES (continued)
| |
| SURVEILLANCE SR 3.7.2.6 REQUIREMENTS (continued) This SR verifies that the automatic isolation valves of the RWS System will automatically switch to the safety or emergency position to provide cooling water exclusively to the RHRSW/ESW The Surveillance Frequency Stilling Basin in the pump house during an accident event. This is is controlled under the demonstrated by the use of an actual or simulated initiation signal.
| |
| Surveillance Frequency This SR also verifies the automatic start capability of one of the Control Program. two RWS pumps in each subsystem.
| |
| Operating experience has shown that these components usually this pass the SR when performed at the 24 month Frequency.
| |
| Therefore, this Frequency is concluded to be acceptable from a reliability standpoint.
| |
| REFERENCES 1. UFSAR, Chapter 15.
| |
| : 2. UFSAR, Section 6.2.2.
| |
| : 3. UFSAR, Section 9.2.2.
| |
| : 4. UFSAR, Section 1.8.27.
| |
| 120 DAEC B 3.7-12 TSCR-095
| |
| | |
| ESW System B 3.7.3 BASES ACTIONS B.1 and B.2 (continued) placed in at least Mode 3 within 12 hours and in MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.
| |
| SURVEILLANCE SR 3.7.3.1 REQUIREMENTS Verifying the correct alignment for each power operated, and automatic valve in each ESW subsystem flow path provides assurance that the proper flow paths will exist for ESW operation by ensuring valves are not inadvertently mispositioned. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve is also allowed to be in the nonaccident position, and yet considered in the correct position, provided it can be automatically realigned to its accident position within the required time. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to manual valves or to valves that cannot be inadvertently misaligned, such as check valves. This SR is considered met for OPERABLE valves that are temporarily placed in a position other than the standby readiness position under appropriate administrative and procedural controls.
| |
| The administrative and procedural controls (such as positioning during a Surveillance Test Procedure or operating in accordance with an approved Operating Instruction) ensure the Operators are cognizant of valve positions and ensure valves are promptly returned to the standby readiness position when the evolution is completed.
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| This SR is modified by a Note indicating that isolation of the ESW System to components or systems may render those components or systems inoperable, but does not affect the OPERABILITY of The Surveillance Frequency the ESW System. As such, when all ESW pumps, valves, and is controlled under the piping are OPERABLE, but a branch connection off the main header is isolated, the ESW System is still OPERABLE.
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| Surveillance Frequency Control Program. The 31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions.
| |
| (continued)
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| TSCR-120 DAEC B 3.7-16 Amendment 223
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| | |
| ESW System B 3.7.3 BASES SURVEILLANCE SR 3.7.3.2 REQUIREMENTS (continued) This SR verifies the automatic start capability of the ESW pump in each subsystem. This is demonstrated by the use of an actual or simulated initiation signal.
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| The Surveillance Frequency Operating experience has shown that these components usually this is controlled under the pass the SR when performed at the 24 month Frequency.
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| Surveillance Frequency Therefore, this Frequency is concluded to be acceptable from a Control Program. reliability standpoint.
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| REFERENCES 1. UFSAR, Section 9.2.3.
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| : 2. UFSAR, Chapter 15.
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| 120 DAEC B 3.7-17 TSCR-044A
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| SFU System B 3.7.4 BASES ACTIONS F.1, F.2, and F.3 (continued)
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| LCO 3.0.3 is not applicable in MODE 4 or 5. However, since irradiated fuel assembly movement can occur in MODE 1, 2, or 3, the Required Actions of Condition F are modified by a Note indicating that LCO 3.0.3 does not apply. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, inability to suspend movement of irradiated fuel assemblies is not sufficient reason to require a reactor shutdown.
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| During movement of irradiated fuel assemblies in the secondary containment, during CORE ALTERATIONS, or during OPDRVs, with two SFU subsystems inoperable, or with one or more SFU subsystems inoperable due to an inoperable CBE boundary, action must be taken immediately to suspend activities that present a potential for releasing radioactivity that might require isolation of the CBE. This places the unit in a condition that minimizes the accident risk.
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| If applicable, CORE ALTERATIONS and movement of irradiated fuel assemblies in the secondary containment must be suspended immediately. Suspension of these activities shall not preclude completion of movement of a component to a safe position. If applicable, action must be initiated immediately to suspend OPDRVs to minimize the probability of a vessel draindown and subsequent potential for fission product release. Action must continue until the OPDRVs are suspended.
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| SURVEILLANCE SR 3.7.4.1 REQUIREMENTS Operating each SFU subsystem for 15 minutes ensures that both subsystems are OPERABLE and that all associated controls are functioning properly. It also ensures that blockage or fan or motor failure, can be detected for corrective action. Since the SFU charcoal is tested at a Relative Humidity 95%, extended operation of the electric heaters is not required. Thus, each subsystem need only be operated for 15 minutes to demonstrate the function of each subsystem. The function of the SFU electric The Surveillance Frequency heaters is to pre-heat incoming air to above 40°F to ensure is controlled under the adsorption occurs within the temperature range that charcoal Surveillance Frequency testing is performed. The 31 day Frequency was developed in Control Program. consideration of the known reliability of fan motors and controls and the redundancy available in the system.
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| (continued) 120 DAEC B 3.7-24A TSCR-092
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| SFU System B 3.7.4 BASES SURVEILLANCE SR 3.7.4.2 REQUIREMENTS (continued) This SR verifies that the required SFU testing is performed in accordance with the Ventilation Filter Testing Program (VFTP).
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| The VFTP includes testing HEPA filter performance, charcoal adsorber efficiency, minimum system flow rate, and the physical properties of the activated charcoal (general use and following specific operations). Specific test Frequencies and additional information are discussed in detail in the VFTP.
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| SR 3.7.4.3 This SR verifies that on an actual or simulated initiation signal, each SFU subsystem starts and operates. This SR also ensures that the control building isolates. The LOGIC SYSTEM The Surveillance Frequency FUNCTIONAL TEST in LCO 3.3.7.1, "Standby Filter Unit is controlled under the Instrumentation," overlaps this SR to provide complete Surveillance Frequency testing of the safety function. While this Surveillance can be Control Program. performed with the reactor at power, operating experience has shown that these components usually pass the Surveillance when that performed at the 24 month Frequency. Therefore, the Frequency was found to be acceptable from a reliability standpoint.
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| SR 3.7.4.4 This SR verifies the OPERABILITY of the CBE boundary by testing for unfiltered air inleakage past the CBE boundary and into the CBE. The details of the testing are specified in the Control Building Envelope Habitability Program.
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| The CBE is considered habitable when the radiological dose to CBE occupants calculated in the licensing basis analyses of DBA consequences is no more than 5 rem TEDE and the CBE occupants are protected from hazardous chemicals and smoke.
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| For DAEC, there is no automatic SFU actuation for hazardous chemical releases or smoke and there are no Surveillance Requirements that verify OPERABILITY in cases of hazardous chemicals or smoke. This SR verifies that the unfiltered air inleakage into the CBE is no greater than the flow rate assumed in the licensing basis analyses of DBA consequences. When unfiltered air inleakage is greater than the assumed flow rate, Condition B must be entered. Required Action B.3 allows time to restore the CBE boundary to OPERABLE status provided mitigating actions can ensure that the CBE remains within the licensing basis habitability limits for the occupants following an accident. Compensatory measures are discussed in Regulatory Guide 1.196, Section C.2.7.3, (Ref. 4) which endorses, with (continued) 120 DAEC B 3.7-24B TSCR-092
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| | |
| CBC System B 3.7.5 BASES ACTIONS E.1, E.2, and E.3 (continued)
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| During movement of irradiated fuel assemblies in the secondary containment, during CORE ALTERATIONS, or during OPDRVs, if Required Actions B.1 and B.2 cannot be met within the required Completion Times, action must be taken to immediately suspend activities that present a potential for releasing radioactivity that might require isolation of the control building. This places the unit in a condition that minimizes risk.
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| If applicable, CORE ALTERATIONS and handling of irradiated fuel in the secondary containment must be suspended immediately. Suspension of these activities shall not preclude completion of movement of a component to a safe position. Also, if applicable, actions must be initiated immediately to suspend OPDRVs to minimize the probability of a vessel draindown and subsequent potential for fission product release. Actions must continue until the OPDRVs are suspended.
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| SURVEILLANCE SR 3.7.5.1 REQUIREMENTS The Surveillance Frequency is This SR verifies that the heat removal capability of the system is controlled under the Surveillance sufficient to remove available control building heat load. The 92 day Frequency is appropriate since significant degradation of the Frequency Control Program.
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| CBC System is not expected over this time period.
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| REFERENCES 1. UFSAR, Section 9.4.4.2.
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| 120 DAEC B 3.7-29 TSCR-068
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| Main Condenser Offgas B 3.7.6 BASES (continued)
| |
| SURVEILLANCE SR 3.7.6.1 a periodic REQUIREMENTS This SR, on a 31 day Frequency, requires an isotopic analysis of an offgas sample to ensure that the required limits are satisfied.
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| The noble gases to be sampled are Xe-133, Xe-135, Xe-138, Kr-85m, Kr-87, and Kr-88. If the measured rate of radioactivity increases significantly (by 50% after correcting for expected increases due to changes in THERMAL POWER), an isotopic analysis is also performed within 4 hours after the increase is The Surveillance Frequency noted, to ensure that the increase is not indicative of a sustained is controlled under the increase in the radioactivity rate. The 31 day Frequency is Surveillance Frequency adequate in view of other instrumentation that continuously Control Program. monitor the offgas, and is acceptable, based on operating experience.
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| This SR is modified by a Note indicating that the SR is not required to be performed until 31 days after any main steam line is not isolated and the SJAE is in operation. Only in this condition can radioactive fission gases be in the Main Condenser Offgas System at significant rates.
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| REFERENCES 1. UFSAR, Section 11.3.3.
| |
| : 2. 10 CFR 50.67.
| |
| : 3. UFSAR, Section 15.2.1.5.
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| 120 DAEC B 3.7-32 TSCR-044A
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| | |
| Main Turbine Bypass System B 3.7.7 BASES ACTIONS B.1 (continued)
| |
| If the Main Turbine Bypass System cannot be restored to OPERABLE status and the MCPR limits for an inoperable Main Turbine Bypass System are not applied, THERMAL POWER must be reduced to < 21.7% RTP. As discussed in the Applicability section, operation at < 21.7% RTP results in sufficient margin to the required limits, and the Main Turbine Bypass System is not required to protect fuel integrity during the Feedwater Controller Failure Maximum Demand transient. The 4 hour Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.
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| SURVEILLANCE SR 3.7.7.1 REQUIREMENTS Cycling each main turbine bypass valve through one complete cycle The Surveillance Frequency of full travel demonstrates that the valves are mechanically is controlled under the OPERABLE and will function when required. The 92 day Frequency Surveillance Frequency is based on operating experience, is consistent with the procedural Control Program. controls governing valve operation, and ensures correct valve positions. Operating experience has shown that these components usually pass the SR when performed at the 92 day Frequency. this Therefore, the Frequency is acceptable from a reliability standpoint.
| |
| In addition, because this SR makes the RPS and EOC-RPT trips on TSV and TCV closure inoperable when performed above 26% RTP (Ref. SRs 3.3.1.1.16 and 3.3.4.1.4), the Frequency also considers the impact on those functions as well.
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| SR 3.7.7.2 The Main Turbine Bypass System is required to actuate automatically to perform its design function. This SR demonstrates The Surveillance Frequency that, with the required system initiation signals, the valves will is controlled under the actuate to their required position. The 24 month Frequency is based Surveillance Frequency on the need to perform this Surveillance under the conditions that Control Program. apply during a plant startup and because of the potential for an unplanned transient if the Surveillance were performed with the reactor at power. In addition, as noted above, cycling the valves also impacts the RPS and EOC-RPT trips on TSV and TCV closure.
| |
| Thus, it is preferable to perform this Surveillance when those trips are not required to be OPERABLE.
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| (continued) 120 DAEC B 3.7-35 TSCR-123
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| | |
| Main Turbine Bypass System B 3.7.7 BASES SURVEILLANCE SR 3.7.7.2 (continued) this REQUIREMENTS Operating experience has shown the 24 month Frequency, which is based on the refueling cycle, is acceptable from a reliability standpoint.
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| SR 3.7.7.3 This SR ensures that the TURBINE BYPASS SYSTEM RESPONSE TIME is in compliance with the assumptions of the The Surveillance Frequency appropriate safety analysis. The response time limits are is controlled under the specified in the UFSAR (Ref. 4). The 24 month Frequency is Surveillance Frequency based on the need to perform this Surveillance under the Control Program. conditions that apply during a unit outage and because of the potential for an unplanned transient if the Surveillance were performed with the reactor at power. In addition, as noted above, cycling the valves also impacts the RPS and EOC-RPT trips on TSV and TCV closure. Thus, it is preferable to perform this Surveillance when those trips are not required to be OPERABLE.
| |
| Operating experience has shown the 24 month Frequency, which this is based on the refueling cycle, is acceptable from a reliability standpoint.
| |
| REFERENCES 1. UFSAR, Section 7.7.2.3.1.
| |
| : 2. UFSAR, Section 15.1.1.1.
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| : 3. UFSAR, Section 10.2.2.
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| : 4. UFSAR, Section 10.4.4.
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| 120 DAEC B 3.7-36 TSCR-123
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| Spent Fuel Storage Pool Water Level B 3.7.8 BASES (continued)
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| LCO The specified water level preserves the assumptions of the fuel handling accident analysis (Ref. 2). As such, it is the minimum required for fuel movement within the spent fuel storage pool.
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| APPLICABILITY This LCO applies during movement of irradiated fuel assemblies in the spent fuel storage pool since the potential for a release of fission products exists.
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| ACTIONS A.1 LCO 3.0.3 is not applicable in MODE 4 or 5. However, since irradiated fuel assembly movement can occur in MODE 1, 2, or 3, required Action A.1 is modified by a Note indicating that LCO 3.0.3 does not apply. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, inability to suspend movement of irradiated fuel assemblies is not a sufficient reason to require a reactor shutdown.
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| When the initial conditions for an accident cannot be met, action must be taken to preclude the accident from occurring. If the spent fuel storage pool level is less than required, the movement of irradiated fuel assemblies in the spent fuel storage pool is suspended immediately. Suspension of this activity shall not preclude completion of movement of an irradiated fuel assembly to a safe position. This effectively precludes a spent fuel handling accident from occurring.
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| SURVEILLANCE SR 3.7.8.1 REQUIREMENTS This SR verifies that sufficient water is available in the event of a The Surveillance Frequency fuel handling accident. The water level in the spent fuel storage is controlled under the pool must be checked periodically. The 7 day Frequency is Surveillance Frequency acceptable, based on operating experience, considering that the Control Program. water volume in the pool is normally stable, and all water level changes are controlled by unit procedures.
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| (continued)
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| TSCR-120 DAEC B 3.7-38 Amendment 223
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| CB/SBGT Instrument Air System B 3.7.9 BASES (continued)
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| SUREVEILLANCE SR 3.7.9.1 REQUIREMENTS Operating each CB/SBGT Instrument Air compressor for 20 minutes allows the oil and other components to reach their operating temperature. This periodic operation The Surveillance Frequency removes condensation which may cause rusting in the is controlled under the cylinders, if it were to accumulate. The 31 day Frequency Surveillance Frequency and the operating time are based on vendor Control Program. recommendations.
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| SR 3.7.9.2 This SR verifies that each CB/SBGT Instrument Air subsystem has the capability to deliver suffcient quantity of compressed air to support the SBGT, SFU, CBC, and containment isolation functions. This SR takes into account both the compressor capacity and the integrity of the distribution system.
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| This SR also verifies the automatic start capability of the The Surveillance Frequency CB/SBGT Instrument Air compressor in each subsystem. This is is controlled under the demonstrated by the use of an actual or simulated initiation signal.
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| Surveillance Frequency Control Program. The 92 day Frequency is consistent with the Frequency for pump testing in accordance with the Inservice Testing Program requirements. Therefore, this Frequency was concluded to be acceptable from a reliability standpoint.
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| REFERENCES 1. UFSAR, Section 9.3.1.2.1.
| |
| : 2. UFSAR, Section 6.2.4.
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| : 3. UFSAR, Section 6.2.5.
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| : 4. UFSAR, Section 6.5.3.3.
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| : 5. UFSAR, Section 6.4.2.
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| : 6. UFSAR, Section 9.4.4.
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| 120 DAEC B 3.7-44 TSCR-006
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| | |
| AC Sources Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.1 REQUIREMENTS (continued) This SR ensures proper circuit continuity for the offsite AC electrical power supply to the onsite distribution network and availability of offsite AC electrical power. The breaker alignment verifies that at least the minimum required offsite power supply breakers are in their correct position to ensure that distribution buses and loads are connected to either the preferred power source or the alternate preferred power source and that appropriate independence of offsite circuits is maintained. This can be accomplished by verifying that an essential bus is energized, and that the status of offsite supply breakers that are The Surveillance Frequency displayed in the control room are correct. The status of manual is controlled under the disconnects is verified administratively. The 7 day Frequency is Surveillance Frequency adequate since breaker position is not likely to change without the Control Program. operator being aware of it and because its status is displayed in the control room.
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| SR 3.8.1.2 and SR 3.8.1.7 These SRs help to ensure the availability of the standby electrical power supply to mitigate DBAs and transients and maintain the unit in a safe shutdown condition.
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| To minimize the wear on moving parts that do not get lubricated when the engine is not running, these SRs have been modified by a Note (Note 2 for SR 3.8.1.2 and Note 1 for SR 3.8.1.7) to indicate that all DG starts for these Surveillances may be preceded by an engine prelube period and (for SR 3.8.1.2 only) followed by a warmup prior to loading. Note 3 to SR 3.8.1.2 allows delaying the entry into associated Conditions and Required Actions for up to two hours during the performance of the conditional surveillance required by Required Actions B.3 or B.4.
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| This Note is necessary because to perform a slow start and warmup of the DG requires reducing the governor control setting to minimum and securing the generator field excitation. The governor control setting is gradually increased to bring the DG to synchronous speed and to allow for warmup. Once the DG is at synchronous speed, the generator field excitation is enabled and the DG is again capable of supplying the essential bus. During this warmup portion of the surveillance test, the DG is incapable of supplying the essential bus and is considered inoperable.
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| (continued)
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| TSCR-120 DAEC B 3.8-15 Amendment 223
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| AC Sources Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.2 and SR 3.8.1.7 (continued)
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| REQUIREMENTS After completion of the SR, the fuel racks to the DG are disabled to allow purging of any residual fuel oil from the cylinders. This also renders the DG inoperable. The two hours allowed by the Note minimizes the amount of time a DG is inoperable while providing enough time to perform the required Conditional Surveillance and avoids entering the shutdown actions of Condition E or F unnecessarily.
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| For the purposes of this testing, the DGs are manually started from standby conditions. Standby conditions for a DG mean that the diesel engine coolant and oil are being continuously circulated and temperature is being maintained consistent with manufacturer recommendations.
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| In order to reduce stress and wear on diesel engines during testing, the manufacturer of the DGs installed at the DAEC recommends a modified start in which the starting speed of the DG is limited, warmup is limited to this lower speed, and the DGs are gradually accelerated to synchronous speed prior to loading.
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| These start procedures are the intent of Note 2 (SR 3.8.1.2).
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| SR 3.8.1.7 requires that, at a 184 day Frequency, the DG starts from standby conditions and achieves required voltage and frequency (i.e. - voltage 3744 V and frequency 59.5 Hz) within 10 seconds; and achieves steady state voltage 3744 V and 4576 V and frequency 59.5 Hz and 60.5 Hz. The 10 second start requirement supports the assumptions in the design basis LOCA analysis of UFSAR, Section 15.2.1 (Ref. 12). The 10 second start requirement is not applicable to SR 3.8.1.2 (see Note 3 of SR 3.8.1.2), when a modified start procedure as described above is used. If a modified start is not used, the 10 second start requirement of SR 3.8.1.7 applies. In addition to the SR requirements, the time for the DG to reach steady state The Surveillance Frequency operation, unless the modified DG start method is employed, is is controlled under the periodically monitored and the trend evaluated to identify degradation of governor and voltage regulator performance.
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| Surveillance Frequency Control Program. The normal 31 day Frequency for SR 3.8.1.2 is consistent with Safety Guide 9. The 184 day Frequency for SR 3.8.1.7 is a reduction in cold testing consistent with Generic Letter 84-15 (Ref. 7). These Frequencies provide adequate assurance of DG OPERABILITY, while minimizing degradation resulting from testing.
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| (continued) 120 DAEC B 3.8-16 TSCR-044A
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| AC Sources Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.3 REQUIREMENTS (continued) This Surveillance verifies that the DGs are capable of synchronizing and can be manually loaded to 2750 kW and 2950 kW, providing a 200 kW range centered on the continuous duty rating of the DGs of 2850 kW. This range ensures that the DGs are tested at a load above the maximum expected accident load. A minimum run time of 60 minutes is required to stabilize engine temperatures, while minimizing the time that the DG is connected to the offsite source.
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| Although no power factor requirements are established by this SR, the DG is normally operated at a power factor greater than 0.9 lagging. While a value of 0.8 is the design rating of the machine, the machine is operated at power factors greater than 0.9 for normal operations and greater than 0.8 for surveillance testing. The load limit is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent The Surveillance Frequency teardown inspections in accordance with vendor is controlled under the recommendations in order to maintain DG OPERABILITY.
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| Surveillance Frequency Control Program. The normal 31 day Frequency for this Surveillance is consistent with Safety Guide 9.
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| Note 1 modifies this Surveillance to indicate that diesel engine runs for this Surveillance may include gradual loading, as recommended by the manufacturer, so that mechanical stress and wear on the diesel engine are minimized. Note 2 modifies this Surveillance by stating that momentary transients because of changing bus loads do not invalidate this test. Similarly, momentary power factor transients above the limit do not invalidate the test.
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| Note 3 indicates that this Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations.
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| Note 4 stipulates a prerequisite requirement for performance of this SR. A successful DG start must precede this test to credit satisfactory performance.
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| (continued) 120 DAEC B 3.8-17 TSCR-103
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| | |
| AC Sources Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.4 REQUIREMENTS (continued) This SR provides verification that the level of fuel oil in the day tank is at or above the level at which the day tank low level alarm is annunciated. This low level alarm should only be received if the automatic fuel oil transfer instrumentation is not functioning properly. The level is expressed as an equivalent volume in gallons, and is selected to ensure adequate fuel oil for a minimum of approximately one hour of DG operation at full load, considering a conservative fuel consumption rate. Verification that at least a one hour supply of fuel oil exists in a day tank provides assurance that a DG can operate continuously, and also The Surveillance Frequency allows the operating crew sufficient time to take corrective action is controlled under the should the automatic fuel oil transfer system not function properly.
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| Surveillance Frequency Control Program. The 31 day Frequency is adequate to ensure that a sufficient supply of fuel oil is available, since low level alarms are provided and facility operators would be aware of any large uses of fuel oil during this period.
| |
| SR 3.8.1.5 Microbiological fouling is a major cause of fuel oil degradation.
| |
| There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water environment in order to survive.
| |
| Testing for water content every 31 days and removal of water from the fuel oil day tanks as necessary, eliminates the necessary environment for bacterial survival. This is the most effective means of controlling microbiological fouling. In addition, it eliminates the potential for water entrainment in the fuel oil during DG operation. Water may come from any of several sources, including condensation, ground water, rain water, contaminated fuel oil, and breakdown of the fuel oil by bacteria. Frequent checking for and removal of accumulated water, as necessary, The Surveillance Frequency minimizes fouling and provides data regarding the watertight is controlled under the integrity of the fuel oil system. The Surveillance Frequencies Surveillance Frequency meet the intent of Regulatory Guide 1.137 (Ref. 10). This SR is Control Program. for preventive maintenance. The presence of water does not necessarily represent a failure of this SR provided that accumulated water is removed during performance of this Surveillance.
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| (continued)
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| TSCR-120 DAEC B 3.8-18 Amendment 223
| |
| | |
| AC Sources Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.6 REQUIREMENTS (continued) This Surveillance demonstrates that each required fuel oil transfer pump operates and transfers fuel oil from its associated storage tank to its associated day tank. It is required to support continuous operation of standby power sources. This Surveillance provides assurance that the fuel oil transfer pump is OPERABLE, the fuel oil piping system is intact, the fuel delivery piping is not obstructed, and the controls and control systems for manual fuel transfer systems are OPERABLE. Additional assurance of fuel oil transfer pump OPERABILITY is provided by The Surveillance Frequency meeting the testing requirements for pumps that are contained in the ASME Boiler and Pressure Vessel Code, Section XI (Ref. 13).
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| is controlled under the Such testing is performed on a quarterly basis.
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| Surveillance Frequency Control Program.
| |
| SR 3.8.1.7 See SR 3.8.1.2.
| |
| SR 3.8.1.8 The slow transfer of each 4.16 kV essential bus power supply from the preferred offsite circuit (i.e. - the startup transformer) to The Surveillance Frequency the alternate preferred offsite circuit (i.e. the standby transformer) is controlled under the demonstrates the OPERABILITY of the alternate preferred circuit Surveillance Frequency distribution network to power the shutdown loads. The 24 month Control Program. Frequency of the Surveillance is based on engineering judgment taking into consideration the plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed on the this 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| This SR is modified by a Note. The reason for the Note is that, during operation with the reactor critical, performance of this SR could cause perturbations to the Electrical Distribution Systems that could challenge continued steady state operation and, as a result, plant safety systems. Credit may be taken for unplanned events that satisfy this SR.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.8-19 Amendment 223
| |
| | |
| AC Sources Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.9 REQUIREMENTS (continued) Each DG is provided with an engine overspeed trip to prevent damage to the engine. Recovery from the transient caused by the loss of a large load could cause diesel engine overspeed, which, if excessive, might result in a trip of the engine. This Surveillance demonstrates the DG load response characteristics and the capability to reject the largest single load and return to the required voltage and frequency (i.e. - voltage 3744 V and 4576 V and frequency 59.5 Hz and 60.5 Hz) within predetermined periods of time (i.e., 1.3 seconds for voltage and 3.9 seconds for frequency) while maintaining an acceptable margin to the overspeed trip. The largest single load for each DG is a core spray pump motor (700 hp). This Surveillance may be accomplished by tripping its associated single largest post-accident load with the DG solely supplying the bus.
| |
| As specified by IEEE-308 (Ref. 14), the load rejection test is acceptable if the increase in diesel speed does not exceed 75% of the difference between synchronous speed and the overspeed trip setpoint, or 15% above synchronous speed, whichever is lower.
| |
| For both DGs, this represents 64.5 Hz, equivalent to 75% of the difference between nominal speed and the overspeed trip setpoint.
| |
| The time, voltage, and frequency tolerances specified in the Bases for this SR are derived from UFSAR Table 8.3-1 (Ref. 16) recommendations for response during load sequence intervals.
| |
| The voltage and frequency are consistent with the design range of the equipment powered by the DG. SR 3.8.1.9.a corresponds to the frequency excursion, while SR 3.8.1.9.b and SR 3.8.1.9.c are the steady state voltage and frequency to which the system must The Surveillance Frequency recover following load rejection within a predetermined time is controlled under the period. The 24 month Frequency is consistent with the Surveillance Frequency recommendation of Regulatory Guide 1.108 (Ref. 9).
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| Control Program.
| |
| This SR is modified by a Note. The reason for the Note is that, during operation with the reactor critical, performance of this SR could cause perturbations to the Electrical Distribution Systems that could challenge continued steady state operation and, as a result, plant safety systems. Credit may be taken for unplanned events that satisfy this SR.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.8-20 Amendment 223
| |
| | |
| AC Sources Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.10 REQUIREMENTS (continued) This Surveillance demonstrates that DG non-critical protective functions (e.g., high jacket water temperature and low lubricating oil pressure) are bypassed on either an ECCS initiation test signal or a LOOP test signal and critical protective functions (engine overspeed and generator differential current) trip the DG to avert substantial damage to the DG unit. The non-critical trips are bypassed during DBAs and LOOPs and provide an alarm on an abnormal engine condition. This alarm provides the operator with The Surveillance Frequency sufficient time to react appropriately. The DG availability to mitigate the DBA is more critical than protecting the engine is controlled under the against minor problems that are not immediately detrimental to Surveillance Frequency emergency operation of the DG.
| |
| Control Program.
| |
| The 24 month Frequency is based on engineering judgment, takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths. Operating experience has shown that these this components usually pass the SR when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required DG from service. Credit may be taken for unplanned events that satisfy this SR.
| |
| SR 3.8.1.11 As specified by Regulatory Guide 1.108 (Ref. 9), paragraph 2.a.(6), this Surveillance ensures that the manual synchronization and load transfer from the DG to the offsite source can be made and that the DG can be returned to ready-to-load status when offsite power is restored. The DG is considered to be in ready-to-load status when the DG is at rated speed and voltage, the output breaker is open and can receive an auto-close signal on bus undervoltage, and the individual pump timers are reset.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.8-21 Amendment 223
| |
| | |
| AC Sources Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.11 (continued)
| |
| REQUIREMENTS The Frequency of 24 months is consistent with the recommendations of Regulatory Guide 1.108 (Ref. 9), paragraph The Surveillance Frequency 2.a.(6), and takes into consideration plant conditions required to is controlled under the perform the Surveillance.
| |
| Surveillance Frequency This SR is modified by a Note. The reason for the Note is that Control Program. performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. Credit may be taken for unplanned events that satisfy this SR.
| |
| SR 3.8.1.12 Under either LOCA conditions or during a loss of offsite power, loads are sequentially connected to the bus by a timed logic sequence using individual time delay relays. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading of the DGs due to high motor starting currents. Verifying the load sequence time interval is greater than or equal to 2 seconds ensures that sufficient time exists for the DG to restore frequency and voltage prior to applying the next load. The Allowable Values for the Core Spray and Low Pressure Coolant Injection Pump Start - Time Delay Relays, Table 3.3.5.1-1, Functions 1.e and 2.e, ensure this time interval is maintained as well as ensuring that safety analysis assumptions regarding ESF equipment time delays are not violated. Allowances for instrument inaccuracies in the load The Surveillance Frequency sequence time interval are also accounted for by the Pump Start -
| |
| is controlled under the Time Delay Relay Allowable Value.
| |
| Surveillance Frequency Control Program. The Frequency of 24 months is consistent with the recommendations of Regulatory Guide 1.108 (Ref. 9),
| |
| paragraph 2.a.(2); takes into consideration plant conditions required to perform the Surveillance; and is intended to be consistent with expected fuel cycle lengths.
| |
| This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. Credit may be taken for unplanned events that satisfy this SR.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.8-22 Amendment 223
| |
| | |
| AC Sources Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.13 (continued)
| |
| REQUIREMENTS loads cannot actually be connected or loaded without undue hardship or potential for undesired operation. For instance, ECCS injection valves are not desired to be stroked open, or systems are not capable of being operated at full flow. In lieu of actual demonstration of connection and loading of these loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable. This testing may include any series The Surveillance Frequency of sequential, overlapping, or total steps so that proper operation is controlled under the with each of the various signals present is verified.
| |
| Surveillance Frequency Control Program. The Frequency of 24 months takes into consideration plant conditions required to perform the Surveillance and is intended to be consistent with an expected fuel cycle length of 24 months.
| |
| Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency. this Therefore, the Frequency is acceptable from a reliability standpoint.
| |
| This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil being continuously circulated and temperature maintained consistent with manufacturer recommendations. The reason for Note 2 is that performing the Surveillance would remove the required offsite circuit from service, perturb the Electrical Distribution System, and challenge safety systems. Credit may be taken for unplanned events that satisfy this SR.
| |
| REFERENCES 1. UFSAR, Section 3.1.2.2.8.
| |
| : 2. UFSAR, Section 8.2.1.3 and Section 8.3.1.1.5
| |
| : 3. UFSAR, Section 1.8.9.
| |
| : 4. FPL letter, L-2006-073, dated April 3, 2006, Response to NRC Generic Letter 2006-02, Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power.
| |
| : 5. UFSAR, Chapter 15.
| |
| (continued) 120 DAEC B 3.8-24 TSCR-082
| |
| | |
| Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES ACTIONS F.1 (continued)
| |
| With a Required Action and associated Completion Time not met, or the stored diesel fuel oil, lube oil, or starting air subsystem not within limits for reasons other than addressed by Conditions A through E, the associated DG may be incapable of performing its intended function and must be immediately declared inoperable.
| |
| SURVEILLANCE SR 3.8.3.1 REQUIREMENTS This SR provides verification that there is an adequate inventory of fuel oil in the storage tank to support a single DG's operation for 7 days at full load. The 7 day period is sufficient time to place the The Surveillance Frequency unit in a safe shutdown condition and to bring in replenishment is controlled under the fuel from an offsite location.
| |
| Surveillance Frequency Control Program. The 31 day Frequency is adequate to ensure that a sufficient supply of fuel oil is available, since low level alarms are provided and unit operators would be aware of any large uses of fuel oil during this period.
| |
| SR 3.8.3.2 This Surveillance ensures that sufficient lubricating oil inventory is available to support at least 7 days of full load operation for each DG. The 257 gallon requirement for each DG is based on the DG manufacturer's consumption values for the run time of the DG.
| |
| Implicit in this SR is the requirement to verify the capability to transfer the lube oil from the lube oil makeup tank to the DG. The requirement is considered to be fulfilled by observing that the DG The Surveillance Frequency lube oil sump level is maintained in the normal band by the lube is controlled under the oil sump level controller.
| |
| Surveillance Frequency Control Program. A 31 day Frequency is adequate to ensure that a sufficient lube oil supply is onsite, since DG starts and run time are closely monitored by the plant staff.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.8-37 Amendment 223
| |
| | |
| Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES SURVEILLANCE SR 3.8.3.3 REQUIREMENTS (continued) The tests listed below are a means of determining that the new and stored fuel oil has not been contaminated with substances that would have an immediate detrimental impact on diesel engine combustion. If results from these tests are within acceptable limits, the fuel oil may be added to the storage tank without concern for contaminating the entire volume of fuel oil in the storage tank. These tests are to be conducted prior to adding the new fuel to the storage tank, but in no case is the time between receipt of new fuel and conducting the tests to exceed 31 days.
| |
| The tests, limits, and applicable ASTM Standards are as follows:
| |
| : a. Sample the new fuel oil in accordance with ASTM D975-77 (Ref. 6);
| |
| : b. Verify in accordance with the tests specified in ASTM D1298-85 (Ref. 6) that the sample has an absolute specific gravity at 60/60F of 0.83 and 0.89 or an API gravity at 60F of 28 and 38;
| |
| : c. Verify in accordance with ASTM D975-77, using ASTM Test Method D88-81, that viscosity at 100F is 32.6 and 40.1 Saybolt Universal Seconds;
| |
| : d. Verify that water and sediment are within limits when tested in accordance with ASTM D975-77 (Ref. 6).
| |
| Failure to meet any of the above limits is cause for rejecting the new fuel oil, but does not represent a failure to meet the LCO concern since the fuel oil is not added to the storage tank.
| |
| Within 31 days following the initial new fuel oil sample, the fuel oil is analyzed to establish that the other properties specified in Table 1 of ASTM D975-77 (Ref. 6) are met for new fuel oil when tested in accordance with ASTM D975-77 (Ref. 6), except that a cloud point limit of 0C has been selected due to fuel oil being stored underground and below the frost line, and that flash point and cetane number are not required. The 31 day period is acceptable because the fuel oil properties of interest, even if they were not within stated limits, would not have an immediate (continued)
| |
| DAEC B 3.8-38 Amendment 223
| |
| | |
| Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES SURVEILLANCE SR 3.8.3.3 (continued)
| |
| REQUIREMENTS effect on DG operation. This Surveillance ensures the availability of high quality fuel oil for the DGs.
| |
| Fuel oil degradation during long term storage shows up as an increase in particulate, mostly due to oxidation. The presence of particulate does not mean that 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.
| |
| Particulate concentrations should be determined in accordance with ASTM D2276-89 (Ref. 6), Method A2 or A3. These methods involve a gravimetric determination of total particulate concentration in the fuel oil and have a limit of 10 mg/l. It is acceptable to obtain a field sample for subsequent laboratory testing in lieu of field testing.
| |
| The Frequency of this test takes into consideration fuel oil degradation trends that indicate that particulate concentration is unlikely to change significantly between Frequency intervals.
| |
| SR 3.8.3.4 This Surveillance ensures that, without the aid of any refill compressor, sufficient air start capacity for each DG is available.
| |
| The system design requirements provide for a minimum of five engine start cycles per air receiver without recharging. The pressure specified in this SR is intended to reflect a conservative The Surveillance Frequency value for which the five starts can be accomplished, assuming is controlled under the only one air start receiver is pressurized.
| |
| Surveillance Frequency Control Program. The 31 day Frequency takes into account the capacity, capability, redundancy, and diversity of the AC sources and the Air Start System for each DG.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.8-39 Amendment 223
| |
| | |
| Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES SURVEILLANCE SR 3.8.3.5 REQUIREMENTS (continued) Microbiological fouling is a major cause of fuel oil degradation.
| |
| There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water environment in order to survive.
| |
| Checking for the presence of water every 31 days, and removing water, as necessary, eliminates the necessary environment for bacterial survival. This is the most effective means of controlling microbiological fouling. In addition, it eliminates the potential for water entrainment in the fuel oil during DG operation. Water may come from any of several sources, including condensation, ground water, rain water, contaminated fuel oil, and from breakdown of the fuel oil by bacteria. Frequent checking for and The Surveillance Frequency removal of water minimizes fouling and provides data regarding is controlled under the the watertight integrity of the fuel oil system. The Surveillance Surveillance Frequency Frequencies are consistent with those recommended and Control Program. established by Regulatory Guide 1.137 (Ref. 2). This SR is for preventive maintenance. The presence of water does not necessarily represent failure of this SR, provided the water is removed during performance of the Surveillance.
| |
| REFERENCES 1. UFSAR, Section 9.5.4.
| |
| : 2. Regulatory Guide 1.137.
| |
| : 3. ANSI N195, 1976.
| |
| : 4. [Deleted]
| |
| : 5. UFSAR, Chapter 15.
| |
| : 6. ASTM Standards: D975-77, D1298-85 and D2276-89.
| |
| : 7. UFSAR, Section 8.3.1.
| |
| 120 DAEC B 3.8-40 TSCR-044A
| |
| | |
| DC Sources Operating B 3.8.4 BASES SURVEILLANCE SR 3.8.4.1 (continued)
| |
| REQUIREMENTS the nominal design voltage of the battery and are consistent with The Surveillance Frequency the initial voltages assumed in the battery margin calculations is controlled under the (Ref. 4). The 7 day Frequency is consistent with manufacturer Surveillance Frequency recommendations and with the intent of IEEE-450 (Ref. 7).
| |
| Control Program.
| |
| SR 3.8.4.2 Visual inspection to detect corrosion of the battery cells and connections, or measurement of the resistance of each inter-cell, inter-rack, inter-tier, and terminal connection, provides an indication of physical damage or abnormal deterioration that could potentially degrade battery performance.
| |
| The connection resistance limits established for this SR must be no more than 20% above the resistance as measured during installation or not above the ceiling value established by the manufacturer. The resulting limits are 5.0 E-5 ohms for inter-cell connections and 1.4 E-4 ohms for inter-rack connections, inter-tier connections and terminal connections. The Frequency for these controlled under the inspections, which can detect conditions that can cause power Surveillance Frequency losses due to resistance heating, is 92 days. This Frequency is considered acceptable based on operating experience related to Control Program.
| |
| detecting corrosion trends.
| |
| SR 3.8.4.3 Visual inspection of the battery cells, cell plates, and battery racks provides an indication of physical damage or abnormal deterioration that could potentially degrade battery performance.
| |
| The presence of physical damage or deterioration does not necessarily represent a failure of this SR, provided an evaluation determines that the physical damage or deterioration does not The Surveillance Frequency affect the OPERABILITY of the battery (its ability to perform its is controlled under the design function).
| |
| Surveillance Frequency Control Program. The 12 month Frequency for this SR is consistent with the intent of IEEE-450 (Ref. 7), which recommends detailed visual (continued) 120 DAEC B 3.8-47 TSCR-048
| |
| | |
| DC Sources Operating B 3.8.4 BASES SURVEILLANCE SR 3.8.4.3 (continued)
| |
| REQUIREMENTS inspection of cell condition and rack integrity on a yearly basis.
| |
| SR 3.8.4.4 and SR 3.8.4.5 Visual inspection and resistance measurements of inter-cell, inter-rack, inter-tier, and terminal connections provide an indication of physical damage or abnormal deterioration that could indicate degraded battery condition. The anti-corrosion material is used to help ensure good electrical connections and to reduce terminal deterioration. The visual inspection for corrosion is not intended to require removal of and inspection under each terminal connection.
| |
| The removal of visible corrosion is a preventive maintenance SR.
| |
| The presence of visible corrosion does not necessarily represent a failure of this SR, provided visible corrosion is removed during performance of this Surveillance. The connection resistance limits for this SR must be no more than 20% above the resistance as measured during installation, or not above the ceiling value established by the manufacturer. The resulting limits are 5.0 E-5 The Surveillance Frequency ohms for inter-cell connections and 1.4 E-4 ohms for inter-rack is controlled under the connections, inter-tier connections and terminal connections.
| |
| Surveillance Frequency Control Program. The 12 month Frequency of these SRs is consistent with the intent of IEEE-450 (Ref. 7), which recommends detailed visual inspection of cell condition and inspection of cell to cell and terminal connection resistance on a yearly basis.
| |
| SR 3.8.4.6 Battery charger capability requirements are based on the design capacity of the chargers (Ref. 3). According to the recommendations of Regulatory Guide 1.32 (Ref. 8), the battery charger supply is required to be based on the largest combined demands of the various steady state loads and the charging capacity to restore the battery from the design minimum charge state to the fully charged state, irrespective of the status of the unit during these demand occurences. The minimum required amperes ensures that these requirements can be satisfied.
| |
| (continued) 120 DAEC B 3.8-48 TSCR-048
| |
| | |
| DC Sources Operating B 3.8.4 BASES SURVEILLANCE SR 3.8.4.6 (continued)
| |
| REQUIREMENTS The Frequency is acceptable, given the unit conditions required to perform the test and the other administrative controls existing to ensure adequate charger performance during these 24 month The Surveillance Frequency intervals. In addition, this Frequency is intended to be consistent is controlled under the with expected fuel cycle lengths.
| |
| Surveillance Frequency This SR is modified by a Note. The reason for the Note is that Control Program.
| |
| performing the Surveillance on a required battery charger would remove a required DC electrical power subsystem from service, perturb the electrical distribution system, and challenge safety systems. This Note does not preclude performance of this SR on the "spare" battery charger (i.e., a charger not in-service or "required"). This Note also acknowledges that credit may be taken for unplanned events that satisfy the Surveillance.
| |
| SR 3.8.4.7 A battery service test is a special test of the battery's capability, as found, to satisfy the design requirements (battery duty cycle) of the DC electrical power system. The discharge rate and test length corresponds to the design duty cycle requirements as The Surveillance Frequency specified in Reference 4. The voltage of each cell shall be is controlled under the determined after the discharge. Following discharge, battery cell Surveillance Frequency parameters must be restored in accordance with LCO 3.8.6. The Control Program. Frequency of 24 months is consistent with the maximum length of an operating cycle.
| |
| This SR is modified by two Notes. Note 1 allows the performance of a performance discharge test in lieu of a service test.
| |
| The modified performance discharge test is a simulated duty cycle consisting of just two rates; the one minute rate published for the battery or the largest current load of the duty cycle, followed by the test rate employed for the performance test, both of which envelope the duty cycle of the service test. Since the ampere-hours removed by a rated one minute discharge represents a very small portion of the battery capacity, the test rate can be changed to that for the performance test without compromising the results of the performance discharge test. The battery terminal voltage (continued) 120 DAEC B 3.8-49 TSCR-060
| |
| | |
| DC Sources Operating B 3.8.4 BASES SURVEILLANCE SR 3.8.4.7 (continued)
| |
| REQUIREMENTS for the modified performance discharge test should remain above the minimum battery terminal voltage specified in the battery service test for the duration of time equal to that of the service test.
| |
| A modified discharge test is a test of the battery capacity and its ability to provide a high rate, short duration load (usually the highest rate of the duty cycle). This will often confirm the battery's ability to meet the critical period of the load duty cycle, in addition to determining its percentage of rated capacity. Initial conditions for the modified performance discharge test should be identical to those specified for a service test.
| |
| The reason for Note 2 is that performing the Surveillance would remove a required DC Electrical Power subsystem from service, perturb the Electrical Distribution System, and challenge safety systems. Credit may be taken for unplanned events that satisfy the SR.
| |
| SR 3.8.4.8 A battery performance discharge test is a test of constant current capacity of a battery, normally done in the as found condition, after having been in service, to detect any change in the capacity determined by the acceptance test. The test is intended to determine overall battery degradation due to age and usage.
| |
| A battery modified performance test is described in the Bases for SR 3.8.4.7. Either the battery performance discharge test or the modified performance discharge test is acceptable for satisfying SR 3.8.4.8; however, only the modified performance discharge test may be used to satisfy SR 3.8.4.8 while satisfying the requirements of SR 3.8.4.7 at the same time.
| |
| The acceptance criteria for this Surveillance is consistent with IEEE-450 (Ref. 7) and IEEE-485 (Ref. 9). These references recommend that the battery be replaced if its capacity is below 80% of the manufacturer's rating. A capacity of 80% shows that the battery rate of deterioration is increasing, even if there is ample capacity to meet the load requirements. The Frequency for (continued)
| |
| DAEC B 3.8-50 TSCR-060
| |
| | |
| controlled under the Surveillance Frequency DC Sources Operating Control Program. B 3.8.4 BASES SURVEILLANCE SR 3.8.4.8 (continued) However, if REQUIREMENTS this test is normally 60 months. If the battery shows degradation, or if the battery has reached 85%
| |
| of its expected life and capacity is < 100% of the manufacturer's rating, the Surveillance Frequency is reduced to 12 months.
| |
| However, if the battery shows no degradation but has reached 85% of its expected life, the Surveillance Frequency is only reduced to 24 months for batteries that retain capacity 100% of the manufacturer's rating. Degradation is indicated, according to IEEE-450 (Ref. 7), when the battery capacity drops by more than 10% relative to its capacity on the previous performance test or when it is 10% below the manufacturer's rating. All these Frequencies are consistent with the recommendations in IEEE-450 (Ref. 7).
| |
| This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required DC electrical power subsystem from service, perturb the Electrical Distribution System, and challenge safety systems. Credit may be taken for unplanned events that satisfy the Surveillance.
| |
| Following discharge, battery cell parameters must be restored in accordance with LCO 3.8.6.
| |
| REFERENCES
| |
| : 1. UFSAR, Section 3.1.2.2.8.
| |
| : 2. UFSAR, Section 1.8.6.
| |
| : 3. IEEE Standard 308, 1971.
| |
| : 4. Calculations: CAL-E92-09, CAL-E92-08 and CAL-E92-07, latest approved revisions.
| |
| : 5. UFSAR, Chapter 15.
| |
| : 6. Regulatory Guide 1.93.
| |
| : 7. IEEE Standard 450, 1980.
| |
| : 8. Regulatory Guide 1.32, February 1977.
| |
| : 9. IEEE Standard 485, 1983.
| |
| : 10. UFSAR, Section 8.3.2 120 DAEC B 3.8-51 TSCR-060
| |
| | |
| Battery Cell Parameters B 3.8.6 BASES SURVEILLANCE SR 3.8.6.1 (continued)
| |
| REQUIREMENTS The SR should only be performed when the battery is on a float charge to allow obtaining meaningful, consistent, trendable readings. If the battery is on equalize charge or has been on equalize charge anytime during the previous 72 hours when the SR is due, performance of the SR should be delayed until the battery has been off equalize charge for 72 hours, utilizing the allowance of SR 3.0.2. If it is expected that a battery will need to be on equalize charge when the SR is due and past the extension The Surveillance Frequency time allowed by SR 3.0.2, the SR should be performed early is controlled under the before the battery is placed on equalize charge.
| |
| Surveillance Frequency Control Program.
| |
| SR 3.8.6.2 periodic The actual Surveillance Frequency is controlled The quarterly inspection of specific gravity and voltage is consistent with IEEE-450 (Ref. 3). In addition, within 24 hours of under the Surveillance a battery discharge < 110 V for 125 V and < 220 V for 250 V or a Frequency Control battery overcharge > 150 V for 125 V and > 300 V for 250 V, the Program. battery must be demonstrated to meet Category B limits.
| |
| Transients, such as motor starting transients, which may momentarily cause battery voltage to drop to 110 V for 125 V and 220 V for 250 V, do not constitute a battery discharge provided the battery terminal voltage and float current return to pre-transient values. This inspection is also consistent with IEEE-450 (Ref. 3), which recommends special inspections following a severe discharge or overcharge, to ensure that no significant degradation of the battery occurs as a consequence of such discharge or overcharge.
| |
| SR 3.8.6.3 verifies The This Surveillance verification that the average temperature of representative cells is within limits is consistent with a Surveillance recommendation of IEEE-450 (Ref. 3) that states that the Frequency is temperature of electrolytes in representative cells should be routine controlled determined on a quarterly basis.
| |
| under the Surveillance Lower than normal temperatures act to inhibit or reduce battery Frequency capacity. This SR ensures that the operating temperatures Control remain within an acceptable operating range. This limit is based Program. on manufacturer's recommendations.
| |
| (continued) 120 DAEC B 3.8-59 TSCR-023
| |
| | |
| Distribution Systems Operating B 3.8.7 BASES ACTIONS F.1 (continued)
| |
| With the 125 VDC RCIC MCC inoperable, the equipment powered from the inoperable MCC are not capable of performing their intended functions. Immediately declaring the RCIC System and the outboard RCIC steam line isolation valve (MO-2401) inoperable allows the Actions of the associated LCOs (LCO 3.5.3, RCIC System, and 3.6.1.3, Primary Containment Isolation Valves) to apply appropriate limitations on continued reactor operation.
| |
| G.1 Condition G corresponds to a level of degradation in the electrical distribution system that causes a required safety function to be lost. When more than one AC or DC electrical power distribution subsystem is lost, and this results in the loss of a required function (except as allowed by Condition D), the plant is in a condition outside the accident analysis. Therefore, no additional time is justified for continued operation. LCO 3.0.3 must be entered immediately to commence a controlled shutdown.
| |
| SURVEILLANCE SR 3.8.7.1 REQUIREMENTS This Surveillance verifies that the AC and DC electrical power distribution systems are functioning properly, with the correct circuit breaker alignment. The correct breaker alignment ensures the appropriate separation and independence of the electrical buses are maintained, and power is available to each required bus. The verification of energization of the buses ensures that the required power is readily available for motive as well as control The Surveillance Frequency functions for critical system loads connected to these buses. This is controlled under the may be performed by verifying the absence of low voltage alarms, Surveillance Frequency or by verifying a load powered from the bus is operating. The Control Program. 7 day Frequency takes into account the redundant capability of the AC and DC electrical power distribution subsystems, and other indications available in the control room that alert the operator to subsystem malfunctions.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.8-71 Amendment 223
| |
| | |
| Distribution Systems Operating B 3.8.7 BASES SURVEILLANCE SR 3.8.7.2 REQUIREMENTS (continued) This Surveillance verifies the "break-before-make" coordination of the circuit breakers for the LPCI Swing Bus (1B34A and 1B44A).
| |
| This SR, when coupled with SR 3.5.1.7, demonstrates the ability of the LPCI Swing Bus to perform its intended safety function in support of the LPCI Loop Select design without compromising the independence of the AC Electrical Power Distribution System (Reference 2). Consequently, failure to satisfy this SR requires that both 1B34 and 1B44 buses be declared inoperable, and Condition G be entered until either 1B34 or 1B44 can be isolated from the Swing Bus, as a loss of all low pressure ECCS has The Surveillance Frequency potentially occurred. If the Swing Bus can be isolated from 1B34 is controlled under the or 1B44, then this SR is met, and the AC electrical power Surveillance Frequency distribution subsystems are not inoperable. However, this will Control Program. result in a failure to meet SR 3.5.1.7 (and Condition B of LCO 3.5.1 will be required to be entered since the LPCI system will be inoperable).
| |
| REFERENCES 1. UFSAR, Chapter 15.
| |
| : 2. J. Hall (NRC) to L. Liu (IELP), "LPCI Swing Bus Design Modification (TAC No. 69556)," dated January 19, 1989 120 DAEC B 3.8-72 TSCR-044A
| |
| | |
| Distribution Systems Shutdown B 3.8.8 BASES (continued)
| |
| SURVEILLANCE SR 3.8.8.1 REQUIREMENTS This Surveillance verifies that the AC and DC electrical power distribution subsystems are functioning properly, with the correct circuit breaker alignment. The correct circuit breaker alignment ensures power is available to each required bus. The verification of energization of the buses ensures that the required power is The Surveillance Frequency readily available for motive as well as control functions for critical is controlled under the system loads connected to these buses. The 7 day Frequency Surveillance Frequency takes into account the redundant capability of the electrical power Control Program. distribution subsystems, as well as other indications available in the control room that alert the operator to subsystem malfunctions.
| |
| REFERENCES 1. UFSAR, Chapter 15.
| |
| 120 DAEC B 3.8-78 TSCR-044A
| |
| | |
| Refueling Equipment Interlocks B 3.9.1 BASES (continued)
| |
| SURVEILLANCE SR 3.9.1.1 REQUIREMENTS Performance of a CHANNEL FUNCTIONAL TEST demonstrates each required refueling equipment interlock will function properly when a simulated or actual signal indicative of a required condition is injected into the logic. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay.
| |
| This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. The The Surveillance Frequency CHANNEL FUNCTIONAL TEST may be performed by any series is controlled under the of sequential, overlapping, or total channel steps so that the entire Surveillance Frequency channel is tested.
| |
| Control Program.
| |
| The 7 day Frequency is based on engineering judgment and is considered adequate in view of other indications of refueling interlocks and their associated input status that are available to unit operations personnel.
| |
| REFERENCES 1. UFSAR, Section 3.1.2.3.7.
| |
| : 2. UFSAR, Section 7.6.2.
| |
| : 3. UFSAR, Section 15.1.4.3.
| |
| : 4. UFSAR, Section 15.1.4.4.
| |
| 120 DAEC B 3.9-4 TSCR-044A
| |
| | |
| Refuel Position One-Rod-Out Interlock B 3.9.2 BASES (continued)
| |
| ACTIONS A.1 and A.2 With one or both channels of the refueling position one-rod-out interlock inoperable, the refueling interlocks may not be capable of preventing more than one control rod from being withdrawn. This condition may lead to criticality.
| |
| Control rod withdrawal must be Immediately suspended, and action must be Immediately initiated to fully insert all insertable control rods in core cells containing one or more fuel assemblies.
| |
| Action must continue until all such control rods are fully inserted.
| |
| Control rods in core cells containing no fuel assemblies do not affect the reactivity of the core and, therefore, do not have to be inserted.
| |
| SURVEILLANCE SR 3.9.2.1 REQUIREMENTS Proper functioning of the refueling position one-rod-out interlock requires the reactor mode switch to be in Refuel. During control rod withdrawal in MODE 5, improper positioning of the reactor mode switch could, in some instances, allow improper bypassing of required interlocks. Therefore, this Surveillance imposes an additional level of assurance that the refueling position one-rod-out interlock will be OPERABLE when required. By "locking" the reactor mode switch in the proper position (i.e.,
| |
| removing the reactor mode switch key from the switch while the reactor mode switch is positioned in Refuel), an additional The Surveillance Frequency administrative control is in place to preclude operator errors from is controlled under the resulting in unanalyzed operation.
| |
| Surveillance Frequency Control Program. The Frequency of 12 hours is sufficient in view of other administrative controls utilized during refueling operations to ensure safe operation.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.9-7 Amendment 223
| |
| | |
| Refuel Position One-Rod-Out Interlock B 3.9.2 BASES SURVEILLANCE SR 3.9.2.2 REQUIREMENTS (continued) Performance of a CHANNEL FUNCTIONAL TEST on each channel demonstrates the associated refuel position one-rod-out interlock will function properly when a simulated or actual signal indicative of a required condition is injected into the logic. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. The CHANNEL FUNCTIONAL TEST may The Surveillance Frequency be performed by any series of sequential, overlapping, or total is controlled under the channel steps so that the entire channel is tested. The 7 day Surveillance Frequency Frequency is considered adequate because of demonstrated Control Program. circuit reliability, procedural controls on control rod withdrawals, and visual and audible indications available in the control room to alert the operator to control rods not fully inserted. To perform the required testing, the applicable condition must be entered (i.e., a control rod must be withdrawn from its full-in position). Therefore, SR 3.9.2.2 has been modified by a Note that states the CHANNEL FUNCTIONAL TEST is not required to be performed until 1 hour after any control rod is withdrawn.
| |
| REFERENCES 1. UFSAR, Section 3.1.2.3.7.
| |
| : 2. UFSAR, Section 7.6.2.
| |
| : 3. UFSAR, Section 15.1.4.3.
| |
| 120 DAEC B 3.9-8 TSCR-044A
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| | |
| Control Rod Position B 3.9.3 BASES (continued)
| |
| LCO All control rods must be fully inserted during applicable refueling conditions to minimize the probability of an inadvertent criticality during refueling.
| |
| APPLICABILITY During MODE 5, loading fuel into core cells with control rods withdrawn may result in inadvertent criticality. Therefore, the control rods must be inserted before loading fuel into a core cell.
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| All control rods must be inserted before loading fuel to ensure that a fuel loading error does not result in loading fuel into a core cell with the control rod withdrawn.
| |
| In MODES 1, 2, 3, and 4, the reactor pressure vessel head is on, and no fuel loading activities are possible. Therefore, this Specification is not applicable in these MODES.
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| ACTIONS A.1 With all control rods not fully inserted during the applicable conditions, an inadvertent criticality could occur that is not analyzed in the UFSAR. All fuel loading operations must be Immediately suspended. Suspension of these activities shall not preclude completion of movement of a component to a safe position.
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| SURVEILLANCE SR 3.9.3.1 REQUIREMENTS During refueling, to ensure that the reactor remains subcritical, all control rods must be fully inserted prior to and during fuel loading.
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| The Surveillance Frequency Periodic checks of the control rod position ensure this condition is is controlled under the maintained. The 12 hour Frequency takes into consideration the Surveillance Frequency procedural controls on control rod movement during refueling as Control Program. well as the redundant functions of the refueling interlocks.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.9-10 Amendment 223
| |
| | |
| Control Rod OPERABILITY - Refueling B 3.9.5 BASES SURVEILLANCE SR 3.9.5.1 and SR 3.9.5.2 (continued)
| |
| REQUIREMENTS The 7 day Frequency takes into consideration equipment reliability, procedural controls over the scram accumulators, and The Surveillance Frequency control room alarms and indicating lights that indicate low is controlled under the accumulator charge pressures.
| |
| Surveillance Frequency Control Program. SR 3.9.5.1 is modified by a Note that allows 7 days after withdrawal of the control rod to perform the Surveillance. This acknowledges that the control rod must first be withdrawn before performance of the Surveillance, and therefore avoids potential conflicts with SR 3.0.3 and SR 3.0.4.
| |
| REFERENCES 1. UFSAR, Section 3.1.2.3.7.
| |
| : 2. UFSAR, Section 15.1.4.3.
| |
| : 3. UFSAR, Section 15.1.4.4.1.
| |
| 120 DAEC B 3.9-18 TSCR-044A
| |
| | |
| The Surveillance Frequency is controlled under the RPV Water Level Surveillance Frequency B 3.9.6 Control Program.
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| BASES SURVEILLANCE SR 3.9.6.1 (continued)
| |
| REQUIREMENTS The Frequency of 24 hours is based on engineering judgment and is considered adequate in view of the large volume of water and the normal procedural controls on valve positions, which make significant unplanned level changes unlikely.
| |
| REFERENCES 1. UFSAR, Section 15.2.5.
| |
| : 2. Regulatory Guide 1.183.
| |
| 120 DAEC B 3.9-21 TSCR-044A
| |
| | |
| RHR - High Water Level B 3.9.7 BASES ACTIONS C.1 and C.2 (continued)
| |
| If no RHR shutdown cooling is in operation when reactor coolant temperature is 150°F, except as permitted by the LCO Note, an alternate method of coolant circulation is required to be established within 1 hour. However, with the water level high, coolant circulation is assured by virtue of being flooded up to a level significantly higher than the minimum natural circulation level (i.e., lowest turnaround point for water in the steam separator) and thus, Required Action C.1 is met.
| |
| During the period of time when the reactor coolant is either being naturally circulated or circulated by another alternate method, the reactor coolant temperature must be periodically monitored to ensure proper circulation is maintained. The once per hour Completion Time is deemed appropriate due to the passive nature of the circulation process.
| |
| SURVEILLANCE SR 3.9.7.1 REQUIREMENTS This Surveillance demonstrates that the RHR subsystem is in operation and circulating reactor coolant when reactor coolant temperature is 150°F.
| |
| The flow rate is determined by the flow rate necessary to provide The Surveillance Frequency sufficient decay heat removal capability corresponding to the is controlled under the decay heat load that is present. The Frequency of 12 hours is Surveillance Frequency sufficient in view of other visual and audible indications available Control Program. to the operator for monitoring the RHR subsystem in the control room.
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| REFERENCES 1. UFSAR, Section 3.1.2.4.5.
| |
| : 2. UFSAR, Section 5.4.7.2.2.
| |
| TSCR-120 DAEC B 3.9-26 Amendment 223
| |
| | |
| RHR - Low Water Level B 3.9.8 BASES (continued)
| |
| SURVEILLANCE SR 3.9.8.1 REQUIREMENTS This Surveillance demonstrates that one RHR shutdown cooling subsystem is in operation and circulating reactor coolant. The The Surveillance Frequency flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability corresponding to the is controlled under the decay heat load that is present.
| |
| Surveillance Frequency Control Program. The Frequency of 12 hours is sufficient in view of other visual and audible indications available to the operator for monitoring the RHR subsystems in the control room.
| |
| REFERENCES 1. UFSAR, Section 3.1.2.4.5.
| |
| : 2. UFSAR, Section 5.4.7.2.2.
| |
| TSCR-120 DAEC B 3.9-31 Amendment 223
| |
| | |
| Reactor Mode Switch Interlock Testing B 3.10.2 BASES (continued)
| |
| SURVEILLANCE SR 3.10.2.1 and SR 3.10.2.2 REQUIREMENTS Meeting the requirements of this Special Operations LCO maintains operation consistent with or conservative to operating with the reactor mode switch in the Shutdown position (or the Refuel position for MODE 5). The functions of the reactor mode switch interlocks that are not in effect, due to the testing in progress, are adequately compensated for by the Special Operations LCO requirements. The administrative controls are to The Surveillance Frequency be periodically verified to ensure that the operational requirements is controlled under the continue to be met. The Surveillances performed at the 12 hour Surveillance Frequency and 24 hour Frequencies are intended to provide appropriate Control Program. assurance that each operating shift is aware of and verifies compliance with these Special Operations LCO requirements.
| |
| REFERENCES 1. UFSAR, Section 7.2.1.1.6.
| |
| : 2. UFSAR, Section 15.1.4.3.
| |
| : 3. UFSAR, Section 15.1.4.4.1.
| |
| 120 DAEC B 3.10-10 TSCR-044A
| |
| | |
| Single Control Rod Withdrawal-Hot Shutdown B 3.10.3 BASES SURVEILLANCE SR 3.10.3.1, SR 3.10.3.2, and SR 3.10.3.3 (continued)
| |
| REQUIREMENTS It is preferred to electrically disarm the control rods since, in this case, drive water cools and minimizes crud accumulation in the drive. SR 3.10.3.2 has been modified by a Note, which clarifies that this SR is not required to be met if SR 3.10.3.1 is satisfied for LCO 3.10.3.d.1 requirements, since SR 3.10.3.2 demonstrates that the alternative LCO 3.10.3.d.2 requirements are satisfied.
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| The Surveillance Frequency Also, SR 3.10.3.3 verifies that all control rods other than the is controlled under the control rod being withdrawn are fully inserted. The 24 hour Surveillance Frequency Frequency is acceptable because of the administrative controls on Control Program. control rod withdrawal, the protection afforded by the LCOs involved, and hard-wired interlocks that preclude additional control rod withdrawals.
| |
| REFERENCES 1. UFSAR, Section 15.1.4.3.
| |
| 120 DAEC B 3.10-15 TSCR-044A
| |
| | |
| Single Control Rod Withdrawal- Cold Shutdown B 3.10.4 BASES (continued)
| |
| SURVEILLANCE SR 3.10.4.1, SR 3.10.4.2, SR 3.10.4.3, and SR 3.10.4.4 REQUIREMENTS The other LCOs made applicable by this Special Operations LCO are required to have their associated surveillances met to establish that this Special Operations LCO is being met. If the local array of control rods is inserted and disarmed while the scram function for the withdrawn rod is not available, periodic verification is required to ensure that the possibility of criticality remains precluded. The control rods can be hydraulically disarmed by closing the drive water and exhaust water isolation valves. Electrically, the control rods can be disarmed by disconnecting power from all four directional control valve solenoids. It is preferred to electrically disarm the control rods since, in this condition, drive water cools and minimizes crud accumulation in the drive. Verification that all the other control rods are fully inserted is required to meet the SDM requirements.
| |
| Verification that a control rod withdrawal block has been inserted ensures that no other control rods can be inadvertently withdrawn The Surveillance Frequency under conditions when position indication instrumentation is is controlled under the inoperable for the affected control rod. The 24 hour Frequency is Surveillance Frequency acceptable because of the administrative controls on control rod Control Program. withdrawals, the protection afforded by the LCOs involved, and hard-wired interlocks to preclude an additional control rod withdrawal.
| |
| SR 3.10.4.2 and SR 3.10.4.4 have been modified by Notes, which clarify that these SRs are not required to be met if the alternative requirements demonstrated by SR 3.10.4.1 are satisfied.
| |
| REFERENCES 1. UFSAR, Section 15.1.4.3.
| |
| 120 DAEC B 3.10-20 TSCR-044A
| |
| | |
| Single CRD Removal Refueling B 3.10.5 BASES SURVEILLANCE SR 3.10.5.1, SR 3.10.5.2, SR 3.10.5.3, SR 3.10.5.4, REQUIREMENTS and SR 3.10.5.5 (continued) is required to ensure the assumptions of the safety analysis are satisfied. Periodic verification of the administrative controls The Surveillance Frequency established by this Special Operations LCO is prudent to preclude is controlled under the the possibility of an inadvertent criticality. The 24 hour Frequency Surveillance Frequency is acceptable, given the administrative controls on control rod Control Program. removal and hard-wired interlocks to block an additional control rod withdrawal.
| |
| REFERENCES 1. UFSAR, Section 15.1.4.3.
| |
| 120 DAEC B 3.10-25 TSCR-044A
| |
| | |
| Multiple Control Rod Withdrawal Refueling B 3.10.6 BASES (continued)
| |
| APPLICABILITY Operation in MODE 5 is controlled by existing LCOs. The exceptions from other LCO requirements (e.g., the ACTIONS of LCO 3.9.3, LCO 3.9.4, or LCO 3.9.5) allowed by this Special Operations LCO are appropriately controlled by requiring all fuel to be removed from cells whose "full in" indicators are allowed to be bypassed.
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| ACTIONS A.1, A.2.1, and A.2.2 If one or more of the requirements of this Special Operations LCO are not met, the immediate implementation of these Required Actions restores operation consistent with the normal requirements for refueling (i.e., all control rods inserted in core cells containing one or more fuel assemblies) or with the exceptions granted by this Special Operations LCO. The Completion Times for Required Action A.1, Required Action A.2.1, and Required Action A.2.2 are intended to require that these Required Actions be implemented in a very short time and carried through in an expeditious manner to either initiate action to restore the affected CRDs and insert their control rods, or initiate action to restore compliance with this Special Operations LCO.
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| SURVEILLANCE SR 3.10.6.1, SR 3.10.6.2, and SR 3.10.6.3 REQUIREMENTS Periodic verification of the administrative controls established by The Surveillance Frequency this Special Operations LCO is prudent to preclude the possibility is controlled under the of an inadvertent criticality. The 24 hour Frequency is acceptable, Surveillance Frequency given the administrative controls on fuel assembly and control rod Control Program. removal, and takes into account other indications of control rod status available in the control room.
| |
| REFERENCES 1. UFSAR, Section 15.1.4.3.
| |
| 120 DAEC B 3.10-28 TSCR-044A
| |
| | |
| SDM Test Refueling B 3.10.8 BASES (continued)
| |
| SURVEILLANCE SR 3.10.8.1, SR 3.10.8.2, and SR 3.10.8.3 REQUIREMENTS LCO 3.3.1.1, Functions 2.a and 2.d, made applicable in this Special Operations LCO, are required to have applicable Surveillances met to establish that this Special Operations LCO is being met. However, the control rod withdrawal sequences during the SDM tests may be enforced by the RWM (LCO 3.3.2.1, Function 2, MODE 2 requirements) or by a second licensed operator or other qualified member of the technical staff. As noted, either the applicable SRs for the RWM (LCO 3.3.2.1) must be satisfied according to the applicable Frequencies (SR 3.10.8.2), or the proper movement of control rods must be verified (SR 3.10.8.3). This latter verification (i.e., SR 3.10.8.3) must be performed during control rod movement to prevent deviations from the specified sequence. These surveillances provide adequate assurance that the specified test sequence is being followed.
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| SR 3.10.8.4 Periodic verification of the administrative controls established by The Surveillance Frequency this LCO will ensure that the reactor is operated within the bounds is controlled under the of the safety analysis. The 12 hour Frequency is intended to Surveillance Frequency provide appropriate assurance that each operating shift is aware Control Program. of and verifies compliance with these Special Operations LCO requirements.
| |
| SR 3.10.8.5 Coupling verification is performed to ensure the control rod is connected to the control rod drive mechanism and will perform its intended function when necessary. The verification is required to be performed any time a control rod is withdrawn to the "full out" notch position, or prior to declaring the control rod OPERABLE after work on the control rod or CRD System that could affect coupling. This Frequency is acceptable, considering the low probability that a control rod will become uncoupled when it is not being moved as well as operating experience related to uncoupling events.
| |
| (continued)
| |
| TSCR-120 DAEC B 3.10-37 Amendment 223
| |
| | |
| SDM Test Refueling B 3.10.8 BASES SURVEILLANCE SR 3.10.8.6 REQUIREMENTS (continued) CRD charging water header pressure verification is performed to ensure the motive force is available to scram the control rods in the event of a scram signal. A minimum accumulator pressure is specified, below which the capability of the accumulator to perform its intended function becomes degraded and the accumulator is considered inoperable. The minimum accumulator The Surveillance Frequency pressure of 970 psig is well below the expected pressure of 1100 is controlled under the psig. The 7 day Frequency has been shown to be acceptable Surveillance Frequency through operating experience and takes into account indications Control Program. available in the control room.
| |
| REFERENCES 1. NEDE-24011-P-A-US, General Electric Standard Application for Reactor Fuel, Supplement for United States (as amended).
| |
| : 2. Letter from T. Pickens (BWROG) to G.C. Lainas, NRC, "Amendment 17 to General Electric Licensing Topical Report NEDE-24011-P-A," August 15, 1986.
| |
| TSCR-120 DAEC B 3.10-38 Amendment 223
| |
| | |
| Attachment 5 to NG-11-0037 TSTF-425 (NUREG-1433) vs. DAEC Cross-Reference Technical Specification Section Title/Surveillance TSTF-425 DAEC Notes Description*
| |
| Control Rod Operability 3.1.3 3.1.3 Control rod position 3.1.3.1 3.1.3.1 Notch test - fully withdrawn control rod one notch 3.1.3.2 3.1.3.2 DAEC has Notch test - partially withdrawn control rod one notch 3.1.3.3 3.1.3.2 adopted TSTF-475 Control Rod Scram Times 3.1.4 3.1.4 Scram time testing 3.1.4.2 Control Rod Scram Accumulators 3.1.5 3.1.5 Control rod scram accumulator pressure 3.1.5.1 3.1.5.1 Rod Pattern Control 3.1.6 3.1.6 Analyzed rod position sequence 3.1.6.1 3.1.6.1 Standby Liquid Control (SLC) System 3.1.7 3.1.7 Volume of sodium pentaborate 3.1.7.1 3.1.7.1 Temperature of sodium pentaborate solution 3.1.7.2 3.1.7.2 Temperature of pump suction piping 3.1.7.3 3.1.7.3 Continuity of explosive charge 3.1.7.4 3.1.7.4 Concentration of boron solution 3.1.7.5 3.1.7.5 Manual/power operated valve position 3.1.7.6 --
| |
| DAEC Frequency is Pump flow rate 3.1.7.7 --
| |
| controlled by IST Program Flow through one SLC subsystem 3.1.7.8 3.1.7.7 Heat traced piping is unblocked 3.1.7.9 3.1.7.8 Scram Discharge Volume (SDV) Vent & Drain Valves 3.1.8 3.1.8 Each SDV vent & drain valve open 3.1.8.1 3.1.8.1 DAEC Cycle each SDV vent & drain valve fully closed/fully open Frequency is 3.1.8.2 --
| |
| position controlled by IST Program Each SDV vent & drain valve closes on receipt of scram 3.1.8.3 3.1.8.3 Average Planar Linear Heat Generation Rate (APLHGR) 3.2.1 3.2.1 APLHGR less than or equal to limits 3.2.1.1 3.2.1.1 Minimum Critical Power Ratio (MCPR) 3.2.2 3.2.2 MCPR greater than or equal to limits 3.2.2.1 3.2.2.1 Linear Heat Generation Rate (LHGR) 3.2.3 N/A LHGR less than or equal to limits 3.2.3.1 N/A Average Power Range Monitor (APRM) Gain & Setpoints 3.2.4 N/A MFLPD is within limits 3.2.4.1 N/A APRM setpoints or gain are adjusted for calculated MFLPD 3.2.4.2 N/A Reactor Protection System (RPS) Instrumentation 3.3.1.1 3.3.1.1 Channel Check 3.3.1.1.1 3.3.1.1.1 Absolute diff. between APRM channels & calculated power 3.3.1.1.2 3.3.1.1.2 Page 1 of 13
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| | |
| Attachment 5 to NG-11-0037 TSTF-425 (NUREG-1433) vs. DAEC Cross-Reference Technical Specification Section Title/Surveillance TSTF-425 DAEC Notes Description*
| |
| Consolidated Adjust channel to conform to calibrated flow (APRM STP - Hi) 3.3.1.1.3 3.3.1.1.17 with SR 3.3.1.1.14 Functional Test of automatic scram contactors -- 3.3.1.1.3 Channel Functional Test (after entering Mode 2) 3.3.1.1.4 3.3.1.1.4 Channel Functional Test (7 days) 3.3.1.1.5 3.3.1.1.5 IRM/APRM channel overlap -- 3.3.1.1.7 Calibrate local power range monitors 3.3.1.1.6 3.3.1.1.8 Consolidated Channel Functional Test ([92] days) 3.3.1.1.7 3.3.1.1.9 with SR 3.3.1.1.5 Renumbered Calibrate trip units (92 days) 3.3.1.1.8 3.3.1.1.10 to SR 3.3.1.1.9 Renumbered Channel Calibration (184 days) 3.3.1.1.9 3.3.1.1.12 to SR 3.3.1.1.11 Consolidated Channel Functional Test ([18] month) 3.3.1.1.10 3.3.1.1.13 with SR 3.3.1.1.5 Consolidated with Channel Calibration ([18] month) 3.3.1.1.11 3.3.1.1.14 Renumbered SR 3.3.1.1.11 Verify APRM Flow Biased STP - High 3.3.1.1.12 --
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| Renumbered Logic System Functional Test 3.3.1.1.13 3.3.1.1.15 to SR 3.3.1.1.12 Renumbered Verify TSV/TCV closure/Trip Oil Press-Low Not Bypassed 3.3.1.1.14 3.3.1.1.16 to SR 3.3.1.1.13 Renumbered Verify RPS Response Time 3.3.1.1.15 3.3.1.1.18 to SR 3.3.1.1.15 Renumbered Verify RPS logic system response time -- 3.3.1.1.19 to SR 3.3.1.1.16 Source Range Monitor (SRM) Instrumentation 3.3.1.2 3.3.1.2 Channel Check (12 hours) 3.3.1.2.1 3.3.1.2.1 Verify Operable SRM Detector 3.3.1.2.2 3.3.1.2.2 Consolidated Channel Check (24 hours) 3.3.1.2.3 3.3.1.2.3 with SR 3.3.1.2.1 Renumbered Verify count rate 3.3.1.2.4 3.3.1.2.4 as SR 3.3.1.2.3 Page 2 of 13
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| | |
| Attachment 5 to NG-11-0037 TSTF-425 (NUREG-1433) vs. DAEC Cross-Reference Technical Specification Section Title/Surveillance TSTF-425 DAEC Notes Description*
| |
| Renumbered Channel Functional Test (Mode 5) (7 days) 3.3.1.2.5 3.3.1.2.5 as SR 3.3.1.2.4 Renumbered Channel Functional Test (Modes 2, 3, 4) (31 days) 3.3.1.2.6 3.3.1.2.6 as SR 3.3.1.2.5 Renumbered Channel Calibration 3.3.1.2.7 3.3.1.2.7 as SR 3.3.1.2.6 Control Rod Block Instrumentation 3.3.2.1 3.3.2.1 Channel Functional Test (quarterly) 3.3.2.1.1 3.3.2.1.1 Channel Functional Test (rod withdrawal MODE 2) 3.3.2.1.2 3.3.2.1.2 Channel Functional Test (thermal power < 10% RTP in MODE 1) 3.3.2.1.3 3.3.2.1.3 Verify RBM not bypassed 3.3.2.1.4 3.3.2.1.4 Verify RWM not bypassed (thermal power < 10%) 3.3.2.1.5 --
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| Channel Functional Test 3.3.2.1.6 3.3.2.1.6 Channel Calibration 3.3.2.1.7 3.3.2.1.5 Feedwater & Main Turbine High Water Level Trip 3.3.2.2 N/A Instrumentation Channel Check 3.3.2.2.1 N/A Channel Functional Test 3.3.2.2.2 N/A Channel Calibration 3.3.2.2.3 N/A Logic System Functional Test 3.3.2.2.4 N/A Post Accident Monitor (PAM) Instrumentation 3.3.3.1 3.3.3.1 Channel Check 3.3.3.1.1 3.3.3.1.1 Calibration 3.3.3.1.2 3.3.3.1.2 Remote Shutdown System 3.3.3.2 3.3.3.2 Channel Check 3.3.3.2.1 --
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| Verify control circuit and transfer switch capable of function 3.3.3.2.2 3.3.3.2.1 Channel Calibration 3.3.3.2.3 3.3.3.2.2 End-of-Cycle-Recirculation Pump Trip (RPT) Instrumentation 3.3.4.1 3.3.4.1 Channel Functional Test 3.3.4.1.1 3.3.4.1.1 Calibrate trip units 3.3.4.1.2 --
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| Channel Calibration 3.3.4.1.3 3.3.4.1.2 Logic System Functional Test 3.3.4.1.4 3.3.4.1.3 Verify TSV/TCV Closure/Trip Oil Press-Low Not Bypassed 3.3.4.1.5 3.3.4.1.4 Verify EOC-RPT System Response Time 3.3.4.1.6 3.3.4.1.5 Determine RPT breaker interruption time 3.3.4.1.7 --
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| Anticipated Trip Without Scram-RPT Instrumentation 3.3.4.2 3.3.4.2 Channel Check 3.3.4.2.1 3.3.4.2.1 Channel Functional Test 3.3.4.2.2 3.3.4.2.2 Calibrate trip units 3.3.4.2.3 --
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| Channel Calibration 3.3.4.2.4 3.3.4.2.3 Logic System Functional Test 3.3.4.2.5 3.3.4.2.4 Page 3 of 13
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| | |
| Attachment 5 to NG-11-0037 TSTF-425 (NUREG-1433) vs. DAEC Cross-Reference Technical Specification Section Title/Surveillance TSTF-425 DAEC Notes Description*
| |
| Emergency Core Cooling System (ECCS) Instrumentation 3.3.5.1 3.3.5.1 Channel Check 3.3.5.1.1 3.3.5.1.1 Channel Functional Test (Monthly) -- 3.3.5.1.2 Consolidated Channel Functional Test (92 days) 3.3.5.1.2 3.3.5.1.3 with SR 3.3.5.1.2 Calibrate trip units 3.3.5.1.3 --
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| Renumbered Channel Calibration (92 days) 3.3.5.1.4 3.3.5.1.4 to SR 3.3.5.1.3 Consolidated Channel Functional Test (Annually) -- 3.3.1.5.5 with SR 3.3.5.1.2 Consolidated with Channel Calibration (Annually) -- 3.3.5.1.6 Renumbered SR 3.3.5.1.3 Consolidated with Channel Calibration (18 months) -- 3.3.5.1.7 Renumbered SR 3.3.5.1.3 Consolidated with Channel Calibration ([18] months) 3.3.5.1.5 3.3.5.1.8 Renumbered SR 3.3.5.1.3 Renumbered Logic System Functional Test 3.3.5.1.6 3.3.5.1.9 to SR 3.3.5.1.4 Verify ECCS Response Time 3.3.5.1.7 N/A Reactor Core Isolation Cooling (RCIC) System 3.3.5.2 3.3.5.2 Instrumentation Channel Check 3.3.5.2.1 3.3.5.2.1 Channel Functional Test 3.3.5.2.2 3.3.5.2.2 Calibrate trip units 3.3.5.2.3 --
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| Channel Calibration (92 days) 3.3.5.2.4 --
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| Channel Calibration (Annually) -- 3.3.5.2.3 Consolidated Channel Calibration ([18] months) 3.3.5.2.5 3.3.5.2.4 with SR 3.3.5.2.3 Renumbered Logic System Functional Test 3.3.5.2.6 3.3.5.2.5 as SR 3.3.5.2.4 Primary Containment Isolation Instrumentation 3.3.6.1 3.3.6.1 Channel Check (12 hours) 3.3.6.1.1 3.3.6.1.1 Page 4 of 13
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| | |
| Attachment 5 to NG-11-0037 TSTF-425 (NUREG-1433) vs. DAEC Cross-Reference Technical Specification Section Title/Surveillance TSTF-425 DAEC Notes Description*
| |
| Consolidated Channel Check (Daily) -- 3.3.6.1.2 with SR 3.3.6.1.1 Renumbered Channel Functional Test (Monthly) -- 3.3.6.1.3 as SR 3.3.6.1.2 Consolidated with Channel Functional Test ([92] days) 3.3.6.1.2 3.3.6.1.4 Renumbered SR 3.3.6.1.2 Calibrate trip units 3.3.6.1.3 --
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| Renumbered Channel Calibration (92 days) 3.3.6.1.4 3.3.6.1.5 as SR 3.3.6.1.3 Channel Functional Test ([184] days) 3.3.6.1.5 --
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| Consolidated with Channel Calibration (Semi-annually) -- 3.3.6.1.6 Renumbered SR 3.3.6.1.3 Consolidated with Channel Calibration (Annually) -- 3.3.6.1.7 Renumbered SR 3.3.6.1.3 Consolidated with Channel Calibration ([18] months) 3.3.6.1.6 3.3.6.1.8 Renumbered SR 3.3.6.1.3 Renumbered Logic System Functional Test 3.3.6.1.7 3.3.6.1.9 as SR 3.3.6.1.4 Verify Isolation Response Time 3.3.6.1.8 N/A Secondary Containment Isolation Instrumentation 3.3.6.2 3.3.6.2 Channel Check (12 hours) 3.3.6.2.1 3.3.6.2.1 Consolidated Channel Check (Daily) -- 3.3.6.2.2 with SR 3.3.6.2.1 Renumbered Channel Functional Test 3.3.6.2.2 3.3.6.2.3 as SR 3.3.6.2.2 Calibrate trip units 3.3.6.2.3 --
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| Channel Calibration ([92} days) 3.3.6.2.4 --
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| Renumbered Channel Calibration ([18] months) 3.3.6.2.5 3.3.6.2.4 as SR 3.3.6.2.3 Renumbered Logic System Functional Test 3.3.6.2.6 3.3.6.2.5 as SR 3.3.6.2.4 Page 5 of 13
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| Attachment 5 to NG-11-0037 TSTF-425 (NUREG-1433) vs. DAEC Cross-Reference Technical Specification Section Title/Surveillance TSTF-425 DAEC Notes Description*
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| Verify Isolation Response Time 3.3.6.2.7 N/A Low-Low-Set (LLS) Instrumentation 3.3.6.3 3.3.6.3 Channel Check 3.3.6.3.1 --
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| Channel Functional Test (outside containment) 3.3.6.3.2 3.3.6.3.1 Channel Functional Test (inside containment) 3.3.6.3.3 --
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| Channel Functional Test ([92] days) 3.3.6.3.4 3.3.6.3.2 Calibrate trip units 3.3.6.3.5 --
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| Channel Calibration (Quarterly) -- 3.3.6.3.3 Consolidated Channel Calibration (Semi-annually) -- 3.3.6.3.4 with SR 3.3.6.3.3 Consolidated Channel Calibration ([18] months) 3.3.6.3.6 3.3.6.3.5 with SR 3.3.6.3.3 Renumbered Logic System Functional Test 3.3.6.3.7 3.3.6.3.6 as SR 3.3.6.3.4 Main Control Room Environmental Control (MCREC) 3.3.7.1 3.3.7.1 Instrumentation Channel Check 3.3.7.1.1 3.3.7.1.1 Channel Functional Test 3.3.7.1.2 3.3.7.1.2 Calibrate trip units 3.3.7.1.3 --
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| Channel Calibration 3.3.7.1.4 3.3.7.1.3 Logic System Functional Test 3.3.7.1.5 3.3.7.1.4 Loss of Power (LOP) Instrumentation 3.3.8.1 3.3.8.1 Channel Check 3.3.8.1.1 --
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| Channel Functional Test (31 days) 3.3.8.1.2 3.3.8.1.1 Consolidated Channel Functional Test (Annually) -- 3.3.8.1.2 with SR 3.3.8.1.1 Renumbered Channel Calibration (Annually) -- 3.3.8.1.3 to SR 3.3.8.1.2 Consolidated with Channel Calibration ([18] months) 3.3.8.1.3 3.3.8.1.4 Renumbered SR 3.3.8.1.2 Channel Functional Test (Loss of Voltage) -- 3.3.8.1.3 Renumbered Logic System Functional Test 3.3.8.1.4 3.3.8.1.5 to SR 3.3.8.1.3 RPS Electric Power Monitoring 3.3.8.2 3.3.8.2 Channel Functional Test 3.3.8.2.1 3.3.8.2.1 Channel Calibration 3.3.8.2.2 3.3.8.2.2 System functional test 3.3.8.2.3 3.3.8.2.3 Page 6 of 13
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| Attachment 5 to NG-11-0037 TSTF-425 (NUREG-1433) vs. DAEC Cross-Reference Technical Specification Section Title/Surveillance TSTF-425 DAEC Notes Description*
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| Recirculation Loops Operating 3.4.1 3.4.1 Recirculation loop jet pump flow mismatch 3.4.1.1 3.4.1.1 Verify operation outside Exclusion Zone -- 3.4.1.2 Jet Pumps 3.4.2 3.4.2 Jet pump parameters match established patterns 3.4.2.1 3.4.2.1 Safety/Relief Valves (SRVs) 3.4.3 3.4.3 DAEC Frequency is Safety function lift setpoints 3.4.3.1 --
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| controlled by IST Program SRV opens when manually actuated 3.4.3.2 3.4.3.2 Reactor Coolant System (RCS) Operational Leakage 3.4.4 3.4.4 RCS unidentified and total leakage increase within limits 3.4.4.1 3.4.4.1 RCS Pressure Isolation Valve (PIV) Leakage 3.4.5 N/A Equivalent leakage of each PIV 3.4.5.1 N/A RCS Leakage Detection Instrumentation 3.4.6 3.4.5 Channel Check 3.4.6.1 3.4.5.1 Channel Functional Test (31 days) 3.4.6.2 3.4.5.2 Channel Functional Test (Quarterly) -- 3.4.5.3 Channel Calibration (Quarterly) -- 3.4.5.4 Channel Calibration ([18] months) 3.4.6.3 3.4.5.5 RCS Specific Activity 3.4.7 3.4.6 Dose Equivalent I-131 specific activity 3.4.7.1 3.4.6.1 Residual Heat Removal (RHR) Shutdown Cooling - Hot 3.4.8 3.4.7 Shutdown One RHR Shutdown cooling subsystem operating 3.4.8.1 3.4.7.1 RHR Shutdown Cooling - Cold Shutdown 3.4.9 3.4.8 One RHR Shutdown cooling subsystem operating 3.4.9.1 3.4.8.1 RCS Pressure/Temperature Limit 3.4.10 3.4.9 RCS pressure, temperature, heatup and cooldown rates 3.4.10.1 3.4.9.1 RPV flange/head flange temperatures (tensioning head bolt stud) 3.4.10.7 3.4.9.5 RPV flange/head flange temperatures (after RCS temp < 80°F) 3.4.10.8 3.4.9.6 RPV flange/head flange temperatures (after RCS temp < 100°F) 3.4.10.9 3.4.9.7 Reactor Steam Dome Pressure 3.4.11 3.4.10 Verify reactor steam dome pressure 3.4.11.1 3.4.10.1 ECCS - Operating 3.5.1 3.5.1 Verify injection/spray piping filled with water 3.5.1.1 3.5.1.1 Verify each valve in flow path is in correct position 3.5.1.2 3.5.1.2 Verify ADS header pressure 3.5.1.3 3.5.1.3 Verify RHR (LPCI) cross tie valve is closed and power removed 3.5.1.4 N/A Verify LPCI inverter output voltage 3.5.1.5 N/A Page 7 of 13
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| Attachment 5 to NG-11-0037 TSTF-425 (NUREG-1433) vs. DAEC Cross-Reference Technical Specification Section Title/Surveillance TSTF-425 DAEC Notes Description*
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| DAEC Frequency is Verify ECCS pumps develop specified flow 3.5.1.7 --
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| controlled by IST Program DAEC Frequency is Verify HPCI flow rate (Rx press < 1020, > 920) 3.5.1.8 --
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| controlled by IST Program Verify HPCI flow rate (Rx press < [165] psig) 3.5.1.9 3.5.1.6 Verify ECCS actuates on initiation signal 3.5.1.10 3.5.1.7 Verify ADS actuates on initiation signal 3.5.1.11 3.5.1.8 Verify each ADS valve opens when manually actuated 3.5.1.12 3.5.1.9 ECCS - Shutdown 3.5.2 3.5.2 Verify, for LPCI, suppression pool water level 3.5.2.1 3.5.2.1 Verify, for CS, suppression pool water level and CST water level 3.5.2.2 3.5.2.2 Verify ECCS piping filled with water 3.5.2.3 3.5.2.3 Verify each valve in flow path is in correct position 3.5.2.4 3.5.2.4 DAEC Frequency is Verify each ECCS pump develops flow 3.5.2.5 --
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| controlled by IST Program Verify ECCS actuates on initiation signal 3.5.2.6 3.5.2.6 RCIC System 3.5.3 3.5.3 Verify RCIC piping filled with water 3.5.3.1 3.5.3.1 Verify each valve in flow path is in correct position 3.5.3.2 3.5.3.2 Verify RCIC flow rate (Rx press <1020, >920) 3.5.3.3 DAEC Frequency is controlled by IST Program Verify RCIC flow rate (Rx press < 165) 3.5.3.4 3.5.3.4 Verify RCIC actuates on initiation signal 3.5.3.5 3.5.3.5 Primary Containment 3.6.1.1 3.6.1.1 Verify drywell to suppression chamber differential pressure 3.6.1.1.2 3.6.1.1.2 Primary Containment Air Lock 3.6.1.2 3.6.1.2 Verify only one door can be opened at a time 3.6.1.2.2 3.6.1.2.2 Primary Containment Isolation Valves (PCIVs) 3.6.1.3 3.6.1.3 Verify purge valve is sealed closed 3.6.1.3.1 --
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| Verify each 18 inch purge valve is closed 3.6.1.3.2 3.6.1.3.1 Verify each manual PCIV outside containment is closed 3.6.1.3.3 Verify continuity of traversing incore probe (TIP) shear valve 3.6.1.3.5 3.6.1.3.2 DAEC Frequency is Verify isolation time of each power operated PCIV 3.6.1.3.6 --
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| controlled by IST Program Page 8 of 13
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| Attachment 5 to NG-11-0037 TSTF-425 (NUREG-1433) vs. DAEC Cross-Reference Technical Specification Section Title/Surveillance TSTF-425 DAEC Notes Description*
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| Perform leakage rate testing on each PC purge valve 3.6.1.3.7 3.6.1.3.4 DAEC Frequency is Verify isolation time of MSIVs 3.6.1.3.8 --
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| controlled by IST Program Verify automatic PCIV actuates to isolation position 3.6.1.3.9 3.6.1.3.6 Verify sample of Excess Flow Check Valves actuate 3.6.1.3.10 3.6.1.3.7 DAEC Frequency is Test explosive squib from each shear valve 3.6.1.3.11 --
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| controlled by IST Program Verify each purge valve is blocked 3.6.1.3.15 --
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| Drywell Pressure 3.6.1.4 N/A Verify drywell pressure is within limit 3.6.1.4.1 N/A Drywell Average Air Temperature 3.6.1.5 3.6.1.4 Verify drywell average air temperature is within limit 3.6.1.5.1 3.6.1.4.1 LLS Valves 3.6.1.6 3.6.1.5 Verify each LLS valve opens when manually actuated 3.6.1.6.1 3.6.1.5.1 Verify LLS system actuates on initiation signal 3.6.1.6.2 3.6.1.5.2 Reactor Building - Suppression Chamber Vacuum Breakers 3.6.1.7 3.6.1.6 Verify each vacuum breaker is closed 3.6.1.7.1 3.6.1.6.1 Perform functional test on each vacuum breaker 3.6.1.7.2 3.6.1.6.2 Verify opening setpoint for each vacuum breaker 3.6.1.7.3 3.6.1.6.3 Suppression Chamber - Drywell Vacuum Breakers 3.6.1.8 3.6.1.7 Verify each vacuum breaker is closed 3.6.1.8.1 3.6.1.7.1 Perform functional test on each vacuum breaker 3.6.1.8.2 3.6.1.7.2 Verify opening setpoint for each vacuum breaker 3.6.1.8.3 3.6.1.7.3 Main Steam Isolation Valve (MSIV) Leakage Control System 3.6.1.9 N/A Operate each MSIV LCS blower 3.6.1.9.1 N/A Verify continuity of inboard MSIV LCS heater element 3.6.1.9.2 N/A Perform functional test of each MSIV LCS subsystem 3.6.1.9.3 N/A Suppression Pool Average Temperature 3.6.2.1 3.6.2.1 Verify suppression pool average temperature within limits 3.6.2.1.1 3.6.2.1.1 Suppression Pool Water Level 3.6.2.2 3.6.2.2 Verify suppression pool water level within limits 3.6.2.2.1 3.6.2.2.1 RHR Suppression Pool Cooling 3.6.2.3 3.6.2.3 Verify each valve in flow path is in correct position 3.6.2.3.1 3.6.2.3.1 DAEC Frequency is Verify each RHR pump develops flow rate 3.6.2.3.2 --
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| controlled by IST Program RHR Suppression Pool Spray 3.6.2.4 3.6.2.4 Verify each valve in flow path is in correct position 3.6.2.4.1 --
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| Verify RHR pump develops flow rate 3.6.2.4.2 --
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| Page 9 of 13
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| Attachment 5 to NG-11-0037 TSTF-425 (NUREG-1433) vs. DAEC Cross-Reference Technical Specification Section Title/Surveillance TSTF-425 DAEC Notes Description*
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| Verify spray nozzle unobstructed 3.6.2.4.1 Drywell - Suppression Chamber Differential Pressure 3.6.2.5 N/A Verify differential pressure is within limit 3.6.2.5.1 N/A Drywell Cooling System Fans 3.6.3.1 N/A Operate each fan > 15 minutes 3.6.3.1.1 N/A Verify each fan flow rate 3.6.3.1.2 N/A Primary Containment Oxygen Concentration 3.6.3.2 3.6.3.2 Verify PC oxygen concentration is within limits 3.6.3.2.1 3.6.3.2.1 Containment Atmosphere Dilution (CAD) System 3.6.3.3 N/A Verify CAD liquid nitrogen storage 3.6.3.3.1 N/A Verify each CAD valve in flow path is in correct position 3.6.3.3.2 N/A Secondary Containment 3.6.4.1 3.6.4.1 Verify SC vacuum 3.6.4.1.1 --
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| Verify all SC equipment hatches closed and sealed 3.6.4.1.2 3.6.4.1.1 Verify one SC access door in each opening is closed 3.6.4.1.3 3.6.4.1.2 Verify SC drawn down using one SGTS 3.6.4.1.4 --
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| Verify SC can be maintained using one SGTS 3.6.4.1.5 3.6.4.1.3 Secondary Containment Isolation Valves 3.6.4.2 3.6.4.2 Verify each SC isolation manual valve is closed 3.6.4.2.1 --
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| Verify isolation time of each SCIV 3.6.4.2.2 3.6.4.2.1 Verify each automatic SCIV actuates to isolation position 3.6.4.2.3 3.6.4.2.2 Standby Gas Treatment (SGT) System 3.6.4.3 3.6.4.3 Operate each SGT subsystem with heaters operating 3.6.4.3.1 3.6.4.3.1 Verify each SGT subsystem actuates on initiation signal 3.6.4.3.3 3.6.4.3.3 Verify each SGT filter cooler bypass damper can be opened 3.6.4.3.4 3.6.4.3.4 Residual Heat Removal Service Water (RHRSW) System 3.7.1 3.7.1 Verify each RHRSW valve in flow path in correct position 3.7.1.1 3.7.1.1 Plant Service Water (PSW) System and Ultimate Heat Sink 3.7.2 3.7.2 (UHS)
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| Verify water level in cooling tower basin 3.7.2.1 3.7.2.1 Verify water level in pump well of pump structure 3.7.2.2 --
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| Verify average water temperature of heat sink 3.7.2.3 3.7.2.2 Verify river water depth (Daily) -- 3.7.2.3 Operate each cooling tower fan 3.7.2.4 --
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| Verify each PSW valve in flow path is in correct position 3.7.2.5 3.7.2.4 Verify river water depth (Quarterly) -- 3.7.2.5 Verify PSW actuates on initiation signal 3.7.2.6 3.7.2.6 Diesel Generator (DG) Standby Service Water (SSW) System 3.7.3 3.7.3 Verify each valve in flow path is in correct position 3.7.3.1 3.7.3.1 Verify pump starts automatically 3.7.3.2 3.7.3.2 MCREC System 3.7.4 3.7.4 Operate each MCREC subsystem 3.7.4.1 3.7.4.1 Verify each subsystem actuates on initiation signal 3.7.4.3 3.7.4.3 Page 10 of 13
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| Attachment 5 to NG-11-0037 TSTF-425 (NUREG-1433) vs. DAEC Cross-Reference Technical Specification Section Title/Surveillance TSTF-425 DAEC Notes Description*
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| DAEC has Verify each subsystem can maintain positive pressure 3.7.4.4 -- implemented TSTF-448 Control Room Air Conditioning System 3.7.5 3.7.5 Verify each subsystem has capability to remove heat load 3.7.5.1 3.7.5.1 Main Condenser Offgas 3.7.6 3.7.6 Verify gross gamma activity rate of the noble gases 3.7.6.1 3.7.6.1 Main Turbine Bypass System 3.7.7 3.7.7 Verify one complete cycle of each main turbine bypass valve 3.7.7.1 3.7.7.1 Perform system functional test 3.7.7.2 3.7.7.2 Verify Turbine Bypass System Response Time within limits 3.7.7.3 3.7.7.3 Spent Fuel Storage Pool Water Level 3.7.8 3.7.8 Verify spent fuel storage pool water level 3.7.8.1 3.7.8.1 CB/SBGT Instrument Air System -- 3.7.9 Operate each CB/SBGT Instrument Air compressor -- 3.7.9.1 Verify each CB/SBGT Instrument Air subsystem automatically
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| -- 3.7.9.2 actuates AC Sources - Operating 3.8.1 3.8.1 Verify correct breaker alignment 3.8.1.1 3.8.1.1 Verify each DG starts from standby conditions/steady state 3.8.1.2 3.8.1.2 Verify each DG is synchronized and loaded 3.8.1.3 3.8.1.3 Verify each day tank level 3.8.1.4 3.8.1.4 Check for and remove accumulated water from day tank 3.8.1.5 3.8.1.5 Verify fuel oil transfer system operates 3.8.1.6 3.8.1.6 Verify each DG starts from standby conditions/quick start 3.8.1.7 3.8.1.7 Verify transfer of power from offsite circuit to alternate circuit 3.8.1.8 3.8.1.8 Verify DG rejects load greater than single largest load 3.8.1.9 3.8.1.9 Verify DG maintains load following load reject 3.8.1.10 --
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| Verify on loss of offsite power signal 3.8.1.11 --
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| Verify DG starts on ECCS initiation signal 3.8.1.12 --
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| Verify DG automatic trips bypassed on ECCS initiation signal 3.8.1.13 3.8.1.10 Verify each DG operates for > 24 hours 3.8.1.14 --
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| Verify each DG starts from standby conditions/quick restart 3.8.1.15 --
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| Verify each DG synchronizes with offsite power 3.8.1.16 3.8.1.11 Verify ECCS initiation signal overrides test mode 3.8.1.17 --
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| Verify interval between each timed load block 3.8.1.18 3.8.1.12 Verify on LOOP in conjunction with ECCS initiation signal 3.8.1.19 3.8.1.13 Verify simultaneous DG starts 3.8.1.20 --
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| Diesel Fuel Oil, Lube Oil, and Starting Air 3.8.3 3.8.3 Verify fuel oil storage tank volume 3.8.3.1 3.8.3.1 Verify lube oil inventory 3.8.3.2 3.8.3.2 Verify each DG air start receiver pressure 3.8.3.4 3.8.3.4 Check/remove accumulated water from fuel oil storage tank 3.8.3.5 3.8.3.5 DC Sources - Operating 3.8.4 3.8.4 Page 11 of 13
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| Attachment 5 to NG-11-0037 TSTF-425 (NUREG-1433) vs. DAEC Cross-Reference Technical Specification Section Title/Surveillance TSTF-425 DAEC Notes Description*
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| Verify battery terminal voltage 3.8.4.1 3.8.4.1 Verify no visible corrosion -- 3.8.4.2 Verify no physical damage or abnormal deterioration -- 3.8.4.3 Remove visible corrosion -- 3.8.4.4 Verify connection resistance -- 3.8.4.5 Verify each battery charger supplies amperage 3.8.4.2 3.8.4.6 Verify battery capacity is adequate (service test) 3.8.4.3 3.8.4.7 Verify battery capacity is adequate (performance discharge test) -- 3.8.4.8 Battery Parameters 3.8.6 3.8.6 Verify battery float current 3.8.6.1 --
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| Verify battery pilot cell voltage 3.8.6.2 --
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| Verify battery connected cell electrolyte level 3.8.6.3 --
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| Verify battery pilot cell temperature 3.8.6.4 --
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| Verify battery connected cell voltage 3.8.6.5 --
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| Verify battery cell parameters meet Category A -- 3.8.6.1 Verify battery cell parameters meet Category B -- 3.8.6.2 Verify electrolyte temperature of representative cells -- 3.8.6.3 See 3.8.4.8 Verify battery capacity during performance discharge test 3.8.6.6 --
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| above Inverters - Operating 3.8.7 N/A Verify correct inverter voltage, frequency and alignment 3.8.7.1 N/A Inverters - Shutdown 3.8.8 N/A Verify correct inverter voltage, frequency and alignment 3.8.8.1 N/A Distribution System - Operating 3.8.9 3.8.7 Verify correct breaker alignment/power to distribution 3.8.9.1 3.8.7.1 subsystems Verify LPCI Swing Bus breaker coordination -- 3.8.7.2 Distribution System - Shutdown 3.8.10 3.8.8 Verify correct breaker alignment/power to distribution 3.8.10.1 3.8.8.1 subsystems Refueling Equipment Interlocks 3.9.1 3.9.1 Channel Functional Test of refueling equip interlock inputs 3.9.1.1 3.9.1.1 Refuel Position One-Rod-Out Interlock 3.9.2 3.9.2 Verify reactor mode switch locked in refuel position 3.9.2.1 3.9.2.1 Perform Channel Functional Test 3.9.2.2 3.9.2.2 Control Rod Position 3.9.3 3.9.3 Verify all control rods fully inserted 3.9.3.1 3.9.3.1 Control Rod Operability - Refuel 3.9.5 3.9.5 Insert each withdrawn control rod one notch 3.9.5.1 3.9.5.1 Verify each withdrawn control rod scram accumulator press 3.9.5.2 3.9.5.2 Reactor Pressure Vessel (RPV) Water Level - Irradiated Fuel 3.9.6 3.9.6 Verify RPV water level 3.9.6.1 3.9.6.1 Reactor Pressure Vessel (RPV) Water Level - New Fuel 3.9.7 N/A Verify RPV water level 3.9.7.1 N/A Page 12 of 13
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| Attachment 5 to NG-11-0037 TSTF-425 (NUREG-1433) vs. DAEC Cross-Reference Technical Specification Section Title/Surveillance TSTF-425 DAEC Notes Description*
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| RHR - High Water Level 3.9.8 3.9.7 Verify one RHR shutdown cooling subsystem operating 3.9.8.1 3.9.7.1 RHR - Low Water Level 3.9.9 3.9.8 Verify one RHR shutdown cooling subsystem operating 3.9.9.1 3.9.8.1 Reactor Mode Switch Interlock Testing 3.10.2 3.10.2 Verify all control rods fully inserted in core cells 3.10.2.1 3.10.2.1 Verify no Core Alterations in progress 3.10.2.2 3.10.2.2 Single Control Rod Withdrawal - Hot Shutdown 3.10.3 3.10.3 Verify all control rods in five-by-five array are disarmed 3.10.3.2 3.10.3.2 Verify all control rods other than withdrawn rod are fully inserted 3.10.3.3 3.10.3.3 Single Control Rod Withdrawal - Cold Shutdown 3.10.4 3.10.4 Verify all control rods in five-by-five array are disarmed 3.10.4.2 3.10.4.2 Verify all control rods other than withdrawn rod are fully inserted 3.10.4.3 3.10.4.3 Verify a control rod withdrawal block is inserted 3.10.4.4 3.10.4.4 Single Control Rod Drive (CRD) Removal - Refuel 3.10.5 3.10.5 Verify all control rods other than withdrawn rod are fully inserted 3.10.5.1 3.10.5.1 Verify all control rods in five-by-five array are disarmed 3.10.5.2 3.10.5.2 Verify a control rod withdrawal block is inserted 3.10.5.3 3.10.5.3 Verify no other Core Alterations in progress 3.10.5.5 3.10.5.5 Multiple CRD Removal-Refuel 3.10.6 3.10.6 Verify four fuel assemblies removed from core cells 3.10.6.1 3.10.6.1 Verify all other rods in core cells inserted 3.10.6.2 3.10.6.2 Verify fuel assemblies being loaded comply with reload 3.10.6.3 3.10.6.3 sequence Shutdown Margin Test - Refueling 3.10.8 3.10.8 Verify no other Core Alterations in progress 3.10.8.4 3.10.8.4 Verify CRD charging water header pressure 3.10.8.6 3.10.8.6 Recirculation Loops - Testing 3.10.9 N/A Verify LCO 3.4.1 requirements suspended for < 24 hours 3.10.9.1 N/A Verify Thermal power < 5% RTP during Physics Test 3.10.9.2 N/A Training Startups 3.10.10 N/A Verify all operable IRM channels are <25/40 div. of full scale 3.10.10.1 N/A Verify average reactor coolant temperature < 200 F 3.10.10.2 N/A New Programs (Surveillance Frequency Control Program) 5.5.15 5.5.14 Program
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| * The Technical Specification Section Title/Surveillance Description portion of this attachment is a summary description of the referenced TSTF-425 (NUREG-1433)/DAEC TS Surveillances which is provided for information purposes only and is not intended to be a verbatim description of the TS Surveillances.
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| Page 13 of 13
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| Attachment 6 to NG-11-0037 Page 1 of 2 Proposed No Significant Hazards Consideration Determination Description of Amendment Request:
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| The change requests the adoption of an approved change to the standard technical specifications (STS) for General Electric Plants, BWR/4 (NUREG-1433), to allow relocation of specific TS surveillance frequencies to a licensee-controlled program. The proposed change is described in Technical Specification Task Force (TSTF) Traveler, TSTF-425, Revision 3 (Rev. 3) (ADAMS Accession No. ML090850642) related to the Relocation of Surveillance Frequencies to Licensee ControlRITSTF Initiative 5b and was described in the Notice of Availability published in the Federal Register on July 6, 2009 (74 FR 31996).
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| The proposed changes are consistent with NRC-approved Industry/Technical Specification Task Force (TSTF) Traveler, TSTF-425, Rev. 3, Relocate Surveillance Frequencies to Licensee ControlRITSTF Initiative 5b. The proposed change relocates surveillance frequencies to a licensee-controlled program, the Surveillance Frequency Control Program (SFCP). This change is applicable to licensees using probabilistic risk guidelines contained in NRC-approved NEI 04-10, Risk- Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies, (ADAMS Accession No. 071360456).
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| Basis for proposed no significant hazards consideration: As required by 10 CFR 50.91(a), the NextEra Energy Duane Arnold analysis of the issue of no significant hazards consideration is presented below:
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| : 1. Does the proposed change involve a significant increase in the probability or consequences of any accident previously evaluated?
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| Response: No.
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| The proposed change relocates the specified frequencies for periodic surveillance requirements to licensee control under a new program - the SFCP.
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| Surveillance frequencies are not an initiator to any accident previously evaluated.
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| As a result, the probability of any accident previously evaluated is not significantly increased. The systems and components required by the Technical Specifications (TS) for which the surveillance frequencies are relocated are still required to be operable, meet the acceptance criteria for the surveillance requirements, and be capable of performing any mitigation function assumed in the accident analysis. As a result, the consequences of any accident previously evaluated are not significantly increased.
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| Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.
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| Attachment 6 to NG-11-0037 Page 2 of 2
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| : 2. Does the proposed change create the possibility of a new or different kind of accident from any previously evaluated?
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| Response: No.
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| No new or different accidents result from utilizing the proposed change. The changes do not involve a physical alteration of the plant (i.e., no new or different type of equipment will be installed) or a change in the methods governing normal plant operation. In addition, the changes do not impose any new or different requirements. The changes do not alter assumptions made in the safety analysis.
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| The proposed changes are consistent with the safety analysis assumptions and current plant operating practice.
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| Therefore, the proposed changes do not create the possibility of a new or different kind of accident from any accident previously evaluated.
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| : 3. Does the proposed change involve a significant reduction in the margin of safety?
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| Response: No.
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| The 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 not affected by changes to the surveillance frequencies. Similarly, there is no impact to safety analysis acceptance criteria as described in the plant licensing basis. To evaluate a change in the relocated surveillance frequency, NextEra Energy Duane Arnold will perform a probabilistic risk evaluation using the guidance contained in NRC approved NEI 04-10, Rev.
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| 1 in accordance with the SFCP. NEI 04-10, Rev. 1, methodology provides reasonable acceptance guidelines and methods for evaluating the risk increase of proposed changes to surveillance frequencies consistent with Regulatory Guide 1.177.
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| Therefore, the proposed changes do not involve a significant reduction in a margin of safety.
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| Based upon the reasoning presented above, NextEra Energy Duane Arnold concludes that the requested change does not involve a significant hazards consideration as set forth in 10 CFR 50.92(c), Issuance of Amendment.}}
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