RA-09-065, Application for Technical Specifications Change Regarding Risk-Informed Justification for Relocation of Specific Surveillance Frequency Requirements to Licensee Controlled Program (Adoption of TSTF-425, Rev 3)

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Application for Technical Specifications Change Regarding Risk-Informed Justification for Relocation of Specific Surveillance Frequency Requirements to Licensee Controlled Program (Adoption of TSTF-425, Rev 3)
ML093060126
Person / Time
Site: Oyster Creek
Issue date: 10/30/2009
From: Cowan P
Exelon Generation Co, Exelon Nuclear
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
RA-09-065, TSTF-425, Rev 3
Download: ML093060126 (91)
v • d • e


Text

10 CFR 50.90 RA-09-065 October 30,2009 u.s. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555 Oyster Creek Nuclear Generating Station Renewed Facility Operating License No. DPR-16 NRC Docket No. 50-219

SUBJECT:

Application for Technical Specifications Change Regarding Risk-Informed Justification for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program (Adoption of TSTF-425, Revision 3)

In accordance with the provisions of Title 10 of the Code of Federal Regulations (10 CFR 50.90),

"Application for amendment of license, construction permit, or early site permit," Exelon Generation Company, LLC (Exelon) is submitting a request for an amendment to the Technical Specifications (TS), Appendix A of Renewed Facility Operating License No. DPR-16 for Oyster Creek Nuclear Generating Station (OCNGS).

The proposed amendment would modify OCNGS TS by relocating specific surveillance frequencies to a licensee-controlled program with the implementation of Nuclear Energy Institute (NEI) 04-10, "Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies."

The changes are consistent with NRC-approved Industry Technical Specifications Task Force (TSTF)

Standard Technical Specifications (STS) change TSTF-425, "Relocate Surveillance Frequencies to Licensee Control - Risk Informed Technical Specification Task Force (RITSTF) Initiative 5b, Revision 3, (ADAMS Accession No. ML090850642). The Federal Register notice published on July 6, 2009 (74 FR 31996), announced the availability of this TS improvement. provides a description of the proposed change, the requested confirmation of applicability, and plant-specific verifications. Attachment 2 provides documentation of Probabilistic Risk Assessment (PRA) technical adequacy. Attachment 3 provides the existing OCNGS TS and TS Bases pages marked up to show the proposed changes. Attachment 4 provides a TSTF-425 (NUREG-1433) versus OCNGS TS Cross-Reference. Attachment 5 provides the proposed No Significant Hazards Consideration.

License Amendment Request Adoption of TSTF-425, Rev. 3 Docket No. 50-219 October 30, 2009 Page 2 There are no regulatory commitments contained in this letter.

Exelon requests approval of the proposed license amendment by October 30, 2010, with the amendment being implemented within 120 days.

These proposed changes have been reviewed by the Plant Operations Review Committee and approved in accordance with Nuclear Safety Review Board procedures.

In accordance with 10 CFR 50.91, "Notice for Public Comment; State Consultation," a copy of this application, with attachments, is being provided to the designated State Official.

I declare under penalty of perjury that the foregoing is true and correct. Executed on the 30 th day of October 2009.

If you should have any questions regarding this submittal, please contact Glenn Stewart at 610-765-5529.

Respectfully, Pamela B. Cdwan Director - Licensing & Regulatory Affairs Exelon Generation Company, LLC Attachments: 1. Description and Assessment

2. Documentation of PRA Technical Adequacy
3. Proposed Technical Specification and Bases Page Changes
4. TSTF-425 (NUREG-1433) vs. OCNGS Cross-Reference
5. Proposed No Significant Hazards Consideration cc: Regional Administrator, Region I, USNRC wI attachments USNRC Project Manager, Oyster Creek USNRC Senior Resident Inspector, Oyster Creek Director, Bureau of Nuclear Engineering, New Jersey Department of Environmental Protection

ATTACHMENT 1 License Amendment Request Oyster Creek Nuclear Generating Station Docket No. 50-219 Application for Technical Specification Change Regarding Risk-Informed Justification for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program (Adoption of TSTF-425, Revision 3)

Description and Assessment

LAR - Adoption of TSTF-425, Revision 3 Attachment 1 Docket No. 50-219 Page 1 of 4 DESCRIPTION AND ASSESSMENT

1.0 DESCRIPTION

The proposed amendment would modify the Oyster Creek Nuclear Generating Station (OCNGS) 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 5b (Ref. 1). Additionally, the change would add a new program, the Surveillance Frequency Control Program, to TS Section 6, Administrative Controls.

The changes are consistent with NRC-approved Industry/TSTF Standard Technical Specifications (STS) change TSTF-425, Revision 3, (ADAMS Accession No. ML090850642). The Federal Register notice published on July 6, 2009 (74 FR 31996) (Ref. 2), announced the availability of this TS improvement.

2.0 ASSESSMENT 2.1 Applicability of Published Safety Evaluation Exelon Generation Company, LLC (Exelon) has reviewed the NRC staff's model safety evaluation for TSTF-425, Revision 3, dated July 6, 2009. This review included a review of the NRC staffs model safety evaluation, TSTF-425, Revision 3, and the requirements specified in NEI 04-10, Revision 1, Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies, (ADAMS Accession No. ML071360456) (Ref.

3). includes Exelon's documentation with regard to Probabilistic Risk Assessment (PRA) technical adequacy consistent with the requirements of Regulatory Guide 1.200, Revision 1, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, (ADAMS Accession No. ML070240001) (Ref. 4), 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.

Exelon has concluded that the justifications presented in the TSTF proposal and the NRC staff's model safety evaluation prepared by the NRC staff are applicable to OCNGS and justify this amendment to incorporate the changes to the OCNGS TS.

2.2 Optional Changes and Variations The proposed amendment is consistent with the STS changes described in TSTF-425, Revision 3; however, Exelon proposes variations or deviations from TSTF-425, as identified below, which includes differing Surveillance numbers.

1. Revised (clean) TS pages are not included in this amendment request given the number of TS pages affected, the straightforward nature of the proposed changes, and outstanding OCNGS amendment requests that will impact some of the same TS pages.

Providing only mark-ups of the proposed TS changes satisfies the requirements of 10 CFR 50.90, "Application for amendment of license, construction permit, or early site

LAR - Adoption of TSTF-425, Revision 3 Attachment 1 Docket No. 50-219 Page 2 of 4 permit," (Ref. 5) in that the mark-ups fully describe the changes desired. This is an administrative deviation from the NRC staffs model application dated July 6, 2009 (74 FR 31996) with no impact on the NRC staffs model safety evaluation published in the same Federal Register Notice. As a result of this deviation, the contents and numbering of the attachments for this amendment request differ from the attachments specified in the NRC staffs model application. Also, since the Bases for the OCNGS Surveillance Requirements are intermingled throughout the TS Surveillance Requirement sections, mark-ups of both the proposed TS changes and the proposed TS Bases changes are provided together in Attachment 3.

2. Attachment 4 provides a cross-reference between the NUREG-1433 Surveillances included in TSTF-425 versus the OCNGS Surveillances included in this amendment request. Attachment 4 includes a summary description of the referenced TSTF-425 (NUREG-1433)/OCNGS TS Surveillances, which is provided for information purposes only and is not intended to be a verbatim description of the TS Surveillances. This cross-reference highlights the following:
a. NUREG-1433 Surveillances included in TSTF-425 and corresponding OCNGS Surveillances have differing Surveillances numbers,
b. NUREG-1433 Surveillances included in TSTF-425 that are not contained in the OCNGS TS, and
c. OCNGS plant-specific Surveillances that are not contained in NUREG-1433 and, therefore, are not included in the TSTF-425 mark-ups.

Concerning the above, OCNGS TS are custom TS for a boiling water reactor (BWR) plant.

As a result, the applicable OCNGS TS and associated Bases numbers differ from the Standard Technical Specifications (STS) presented in NUREG-1433 and TSTF-425, Revision 3. This is an administrative deviation from TSTF-425 with no impact on the NRC staffs model safety evaluation dated July 6, 2009 (74 FR 31996).

In addition, there are Surveillances contained in NUREG-1433 that are not contained in the OCNGS TS. Therefore, the NUREG-1433 mark-ups included in TSTF-425 for these Surveillances are not applicable to OCNGS. This is an administrative deviation from TSTF-425 with no impact on the NRC staffs model safety evaluation dated July 6, 2009 (74 FR 31996).

Furthermore, the OCNGS TS include plant-specific Surveillances that are not contained in NUREG-1433 and, therefore, are not included in the NUREG-1433 mark-ups provided in TSTF-425. Exelon has determined that the relocation of the Frequencies for these OCNGS plant-specific Surveillances is consistent with TSTF-425, Revision 3, and with the NRC staff's model safety evaluation dated July 6, 2009 (74 FR 31996), including the scope exclusions identified in Section 1.0, "Introduction," of the model safety evaluation.

Changes to the Frequencies for these plant-specific Surveillances would be controlled under the Surveillance Frequency Control Program (SFCP). The SFCP provides the necessary administrative controls to require that Surveillances 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 NEI 04-10, Revision 1, "Risk-Informed Technical Specifications

LAR - Adoption of TSTF-425, Revision 3 Attachment 1 Docket No. 50-219 Page 3 of 4 Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies," (ADAMS Accession No. ML071360456), as approved by NRC letter dated September 19, 2007 (ADAMS Accession No. ML072570267). The NEI 04-10, Revision 1 methodology includes qualitative considerations, risk analyses, sensitivity studies and bounding analyses, as necessary, and recommended monitoring of the performance of 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) (Ref. 6), relative to changes in Surveillance Frequencies. Therefore, the proposed relocation of the OCNGS plant-specific Surveillance Frequencies is consistent with TSTF-425 and with the NRC staffs model safety evaluation dated July 6, 2009 (74 FR 31996).

3.0 REGULATORY ANALYSIS

3.1 No Significant Hazards Consideration Exelon has reviewed the proposed no significant hazards consideration (NSHC) determination published in the Federal Register dated July 6, 2009 (74 FR 31996). Exelon has concluded that the proposed NSHC presented in the Federal Register notice is applicable to OCNGS, and is provided as Attachment 4 to this amendment request, which satisfies the requirements of 10 CFR 50.91(a), "Notice for public comment; State consultation" (Ref. 7).

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 NRC staff's model safety evaluation published in the Notice of Availability dated July 6, 2009 (74 FR 31996). Exelon has concluded that the relationship of the proposed changes to the applicable regulatory requirements presented in the Federal Register notice is applicable to OCNGS.

3.3 Precedence This application is being made in accordance with the TSTF-425, Revision 3 (ADAMS Accession No. ML090850642). Exelon is not proposing significant variations or deviations from the TS changes described in TSTF 425 or in the content of the NRC staff's model safety evaluation published on July 6, 2009 (74 FR 31996). The NRC has previously approved amendments to the TS as part of the pilot process for TSTF-425, including: Amendment Nos. 186 and 147 for Limerick Generating Station, Units 1 and 2, respectively (TAC Nos. MC3567 and MC3568) dated September 28, 2006; Amendment Nos. 200 and 201 for Diablo Canyon Power Plant, Units 1 and 2, respectively (TAC Nos. MD8911 and 8912), dated October 30, 2008; and Amendment Nos.

188 and 175 for South Texas Project, Units 1 and 2, respectively (TAC Nos. MD7058 and MD7059), dated October 31, 2008. The subject License Amendment Request proposes to relocate periodic surveillance frequencies to a licensee-controlled program and add a new program (the Surveillance Frequency Control Program) to the Administrative Controls section of TS in accordance with TSTF-425 and as discussed in the previously approved amendments.

LAR - Adoption of TSTF-425, Revision 3 Attachment 1 Docket No. 50-219 Page 4 of 4 3.4 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.

4.0 ENVIRONMENTAL CONSIDERATION

Exelon has reviewed the environmental consideration included in the NRC staffs model safety evaluation published in the Federal Register on July 6, 2009 (74 FR 31996). Exelon has concluded that the staffs findings presented therein are applicable to OCNGS, and the determination is hereby incorporated by reference for this application.

5.0 REFERENCES

1. TSTF-425, Revision 3, Relocate Surveillance Frequencies to Licensee Control - RITSTF Initiative 5b, March 18, 2009 (ADAMS Accession Number: ML090850642).
2. NRC Notice of Availability of Technical Specification Improvement to Relocate Surveillance Frequencies to Licensee Control - Risk-Informed Technical Specification Task Force (RITSTF) Initiative 5b, Technical Specification Task Force - 425, Revision 3, published on July 6, 2009 (74 FR 31996).
3. NEI 04-10, Revision 1, Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies, April 2007 (ADAMS Accession Number:

ML071360456).

4. Regulatory Guide 1.200, Revision 1, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, January 2007 (ADAMS Accession Number: ML070240001).
5. 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit."
6. Regulatory Guide 1.177, An Approach for Plant-Specific, Risk-Informed Decisionmaking:

Technical Specifications, dated August 1998 (ADAMS Accession No. ML003740176).

7. 10 CFR 50.91(a), "Notice for public comment; State consultation."

ATTACHMENT 2 License Amendment Request Oyster Creek Nuclear Generating Station Docket No. 50-219 Application for Technical Specification Change Regarding Risk-Informed Justification for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program (Adoption of TSTF-425, Revision 3)

Documentation of PRA Technical Adequacy

LAR - Adoption of TSTF-425, Revision 3 Attachment 2 Docket No. 50-219 Page i of i Documentation of PRA Technical Adequacy TABLE OF CONTENTS Section Page 2.1 Overview .......................................................................................................................... 1 2.2 Technical Adequacy of the PRA Model......................................................................... 3 2.2.1 Plant Changes not yet Incorporated into the PRA Model ...................................... 4 2.2.2 Applicability of Peer Review Findings and Observations ...................................... 4 2.2.3 Consistency with Applicable PRA Standards ........................................................ 6 2.2.4 Identification of Key Assumptions.......................................................................... 6 2.3 External Events Considerations .................................................................................. 13 2.3.1 IPEEE .................................................................................................................. 13 2.3.2 Discussion of External Events Evaluation ........................................................... 13 2.3.3 Summary of External Event Status...................................................................... 15 2.4 Summary........................................................................................................................ 15 2.5 References..................................................................................................................... 15

LAR - Adoption of TSTF-425, Revision 3 Attachment 2 Docket No. 50-219 Page 1 of 16 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 Oyster Creek Nuclear Generating Station (OCNGS) 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.

The following steps of the risk-informed STI revision process are common to proposed changes to all STIs within the proposed licensee-controlled program.

  • 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.
  • A qualitative analysis is performed for each STI revision that involves several considerations as explained in NEI 04-10, Revision 1.
  • Each STI revision is reviewed by an Expert Panel, referred to as the Integrated Decisionmaking 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 future audits by the NRC. If the IDP does not approve the STI revision, the STI value is left unchanged.
  • 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.
  • 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.

  • 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 PRA evaluations (i.e., internal events, external events and shutdown) is also compared to the risk acceptance criteria as delineated in NEI 04-10.

LAR - Adoption of TSTF-425, Revision 3 Attachment 2 Docket No. 50-219 Page 2 of 16 For those cases where the STI can not 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.

The NEI 04-10 methodology endorses the guidance provided in Regulatory Guide (RG) 1.200, Revision 1 [Ref. 2], An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities. The guidance in RG 1.200 indicates that the following steps should be followed when performing PRA assessments (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. The remaining requirements of Section 4.2 are addressed by Item 4 below.):

1. Identify the parts of the PRA used to support the application.

Structures, systems, and components (SSCs), operational characteristics affected by the application and how these are implemented in the PRA model.

A definition of the acceptance criteria used for the application.

2. Identify the scope of risk contributors addressed by the PRA model.

If not full scope (i.e., internal events, external events, all modes), identify appropriate compensatory measures or provide bounding arguments to address the risk contributors not addressed by the PRA model.

3. Summarize the risk assessment methodology used to assess the risk of the application.

Include how the PRA model was modified to appropriately model the risk impact of the change request.

4. Demonstrate the Technical Adequacy of the PRA.

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.

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.

Document that the parts of the PRA used in the decision are consistent with applicable standards endorsed by the Regulatory Guide (currently, RG 1.200, Revision 1, includes only 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.

LAR - Adoption of TSTF-425, Revision 3 Attachment 2 Docket No. 50-219 Page 3 of 16 Identify key assumptions and approximations relevant to the results used in the decision-making process.

The purpose of the remaining portion of this attachment is to address the requirements identified in Item 4 above.

2.2 Technical Adequacy of the PRA Model The 2008A version of the OCNGS PRA model is the most recent evaluation of the risk profile at OCNGS for internal event challenges. The OCNGS 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 OCNGS PRA is based on the event tree / fault tree methodology, which is a well-known methodology in the industry.

Exelon Generation Company, LLC (Exelon) employs a multi-faceted approach to establishing and maintaining the technical adequacy and plant fidelity of the PRA models for all operating Exelon nuclear generation sites. This approach includes both a proceduralized PRA maintenance and update process, and the use of self-assessments and independent peer reviews. The following information describes this approach as it applies to the OCNGS PRA.

PRA Maintenance and Update The Exelon risk management process ensures that the applicable PRA model is an accurate reflection of the as-built and as-operated OCNGS plant. This process is defined in the Exelon Risk Management program, which consists of a governing procedure (ER-AA-600, "Risk Management") and subordinate implementation procedures. Exelon procedure ER-AA-600-1015, "FPIE PRA Model Update," delineates the responsibilities and guidelines for updating the full power internal events PRA models at all operating Exelon nuclear generation sites. The overall Exelon Risk Management program, including ER-AA-600-1015, 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.), and for controlling the PRA model and associated computer files. To ensure that the current PRA model remains an accurate reflection of the as-built, as-operated plant, the following activities are routinely performed:

  • Design changes and procedure changes are reviewed for their impact on the PRA model.
  • New engineering calculations and revisions to existing calculations are reviewed for their impact on the PRA model.
  • Maintenance unavailabilities are captured, and their impact on CDF is trended.
  • Plant specific initiating event frequencies, failure rates, and maintenance unavailabilities are updated approximately every four years.

In addition to these activities, Exelon risk management procedures provide the guidance for particular risk management maintenance activities. This guidance includes:

LAR - Adoption of TSTF-425, Revision 3 Attachment 2 Docket No. 50-219 Page 4 of 16

  • Guidelines for the documentation of the PRA model, PRA products, and technical bases documents.
  • The approach for controlling electronic storage of Risk Management (RM) products including PRA update information, PRA models, and PRA applications.
  • Guidelines for updating the full power, internal events PRA models for Exelon nuclear generation sites.
  • 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 SSCs within the scope of the Maintenance Rule (10CFR50.65 (a)(4)).

In accordance with this guidance, regularly scheduled PRA model updates nominally occur on an approximately 4-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. Exelon completed the 2008A update to the OCNGS PRA model in 2009 as the result of a regularly scheduled update to the previous 2004B PRA model.

As indicated previously, RG 1.200 also requires that additional information be provided as part of the license amendment request (LAR) submittal to demonstrate the technical adequacy of the PRA model used for the LAR 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 in the following subsections.

2.2.1 Plant Changes Not Yet Incorporated into the PRA Model A PRA updating requirements evaluation (URE), which is the Exelon PRA model update tracking database, is created for all issues that are identified that could impact the PRA model.

The URE database includes the identification of those plant changes that could impact the PRA model as one of the types of issues incorporated.

As part of the PRA evaluation for each STI change request, a review of open items in the URE database for OCNGS 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 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.

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 OCNGS PRA model. These assessments are as follows and further discussed in the paragraphs below.

  • An independent PRA peer review was conducted under the auspices of the BWR Owners Group in September 1996, following the Industry PRA Peer

LAR - Adoption of TSTF-425, Revision 3 Attachment 2 Docket No. 50-219 Page 5 of 16 Review process [Ref. 3]. This peer review included an assessment of the PRA model maintenance and update process.

  • During 2005 and 2006, the OCNGS 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 [Ref. 4].
  • A PRA Peer Review of the OCNGS PRA was performed during August 2006 using the Supporting Requirements of the ASME PRA Standard [Ref. 5]. The results of the PRA Peer Review indicated that a very small number of the supporting requirements (SRs) were Not Met. These SRs related principally to documentation and the treatment of modeling uncertainty. The latter remains an open industry and NRC item to be resolved by the issuance of NUREG-1855. These open items were added to the OCNGS URE database and have been evaluated in the 2009 PRA self-assessment.

The results of the focused internal flood PRA Peer Review indicated a small number of the Internal Flood Supporting Requirements were not met. The associated findings were added to the URE database to ensure resolution and have been included in the 2009 PRA self-assessment.

  • In 2009, an update of the PRA self-assessment analysis was performed against ASME PRA Standard, Addendum B [Ref. 6] following completion of the OCNGS 2008A PRA update. The self-assessment considered all of the findings from the 2006 full PRA Peer Review and the 2008 focused PRA Peer Review on Internal Flooding. The 2009 self-assessment also addressed the updated Supporting Requirements associated with PRA Model Uncertainty as provided in the Combined PRA Standard [Ref. 7].

A summary of the disposition of the 1996 Industry PRA Peer Review facts and observations (F&Os) for the OCNGS PRA models was documented as part of the statement of PRA capability for MSPI in the OCNGS MSPI Basis Document [Ref. 4]. As noted in that document, there were three level A and 19 level B F&Os from the 1996 peer review, and all significance level A and B F&Os were previously addressed and closed out with the completion of the 2004B PRA model of record.

A Gap Analysis for the OCNGS PRA model was initially completed in 2004, prior to the 2004B PRA update. This Gap Analysis was performed against the available ASME PRA Standard, Addendum A [Ref. 5]. This gap analysis defined a list of 123 supporting requirements from the Standard for which potential gaps to Capability Category II of the Standard were identified. For each such potential gap, a PRA URE was documented for resolution.

A PRA model update was completed in 2005, resulting in the 2004B updated PRA 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 UREs. Following the update, an assessment of the status of the gap analysis relative to the new PRA model and the updated requirements in Addendum A of

LAR - Adoption of TSTF-425, Revision 3 Attachment 2 Docket No. 50-219 Page 6 of 16 the ASME PRA Standard [Ref. 5] concluded that 78 of the gaps were fully resolved (i.e., are no longer gaps), and another eight were partially resolved. This left 45 of the Supporting Requirements as not yet fully at Capability Category II following the 2004B update.

2.2.3 Consistency with Applicable PRA Standards As indicated above, a PRA model update was completed in 2009, resulting in the 2008A updated PRA model. In updating the PRA, changes were made to the PRA to address most of the previously identified gaps, as well as to address other open UREs. Following the update, an assessment of the status of the gap analysis relative to the new PRA model and the updated requirements in Addendum B of the ASME PRA Standard [Ref. 6] concluded that 28 of the gaps were fully resolved (i.e., are no longer gaps), and another four (4) were partially resolved. After accounting for the number of SRs added or deleted as part of Addendum B, the OCNGS PRA contains 19 potential gaps to Capability Category II of the Standard [Ref. 6]. These SRs are summarized in Table 2-1 along with an assessment of the impact for this STI evaluations.

All remaining gaps will be reviewed for consideration for the next periodic PRA model update (anticipated to be in 2012), 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 in the URE database so that they can be tracked and their potential impacts accounted for in applications where appropriate.

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.

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, 2.2.2, and 2.2.3 above (including a review of identified sources of uncertainty that were developed for OCNGS based on the EPRI 1016737 guidance [Ref. 8]) for each STI change assessment will be documented and included in the results of the risk analysis that is presented to the IDP.

LAR - Adoption of TSTF-425, Revision 3 Attachment 2 Docket No. 50-219 Page 7 of 16 Table 2-1 Status of Identified Gaps to Capability Category II of the ASME PRA Standard Title Description of Gap Applicable SRs Current Status / Comment Importance to Application Gap #1 Reaching a safe stable end state defines the SC-A5 Open. Enhance documentation to justify why Not significant given that the current success of a sequence and therefore the mission extending FTR mission times beyond 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> approach is judged to be reasonable time of the sequence to achieve the Level 1 end for loss of DHR sequences is not necessary. for long term scenarios (e.g., long term state. The mission times for failure to run The considerations that support the choice of loss of DHR).

calculations are assessed at 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or less if the mission time are as follows:

specifically justified. Equipment failure rates (failures/hour) are Extending the FTR mission time beyond 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for judged to be too conservative for times greater loss of DHR sequences is considered to be an than a few hours of operation.

unnecessary complication and does not affect PRA For times greater than a few hours, the ability to insights nor does it significantly affect its quantitative repair and recover equipment can compete with evaluation. the failure rate such that there can be considered to be a steady state equilibrium condition reached.

Gap #2 Include system engineer and operational experience SC-A6 Partially Resolved With Open Item: Not significant. This is judged to be a as well as EOPs and other pertinent operational Performed for a number of systems but not all. documentation consideration only and procedures that mitigate the risk of core damage into does not affect the technical adequacy system analysis. Additionally, document this of the PRA model.

information in the System Notebook.

Gap #3 Strict interpretation of SY-A12 would require SY-A12 Open. Enhance documentation to justify why Not significant. The PRA model is additional investigation in determining whether all certain components and failure modes may be judged to include proper treatment of appropriate components and failure modes are excluded. components and failure modes for included could be performed. Capability Category II requirements.

Gap #4 Document the criteria for how components and SY-A14 Open. Enhance documentation to justify why Not significant. The PRA model is failure modes may be excluded from the model (e.g., certain components and failure modes may be judged to include proper treatment of failure mode is less than 1% of the total failure excluded. components and failure modes for probability for that component). Capability Category II requirements.

Gap #5 Basic event identification nomenclature is SY-A21 Open. Update the basic event identification None. This is judged to be a documented in Appendix A of the OCNGS nomenclature to provide more transparency. documentation consideration only and Component Data Notebook. does not affect the technical adequacy Basic event nomenclature should be made consistent of the PRA model.

with Exelon nomenclature.

The current nomenclature is based on the naming scheme when PRA model was developed in the RISKMAN software environment.

LAR - Adoption of TSTF-425, Revision 3 Attachment 2 Docket No. 50-219 Page 8 of 16 Table 2-1 Status of Identified Gaps to Capability Category II of the ASME PRA Standard Title Description of Gap Applicable SRs Current Status / Comment Importance to Application Gap #6 Strict interpretation of SY-C2 would require the SY-C2 Partially Resolved With Open Item: Enhance None. This is judged to be a following in the System Notebooks: the System Notebook documentation to provide documentation consideration only and

1) References to the data notebook of the more transparency. does not affect the technical adequacy actual operating history indicating any past of the PRA model.

problems with system operation

2) Relationship between system success criteria and accident sequences modeled
3) A listing of components and failure modes included in the model and justification for any exclusions Gap #7 To meet the requirements of SR HR-B1, the following HR-B1 Open. Enhance the Human Reliability Analysis None. This is judged to be a would be developed as supporting documentation for Notebook documentation to provide more documentation consideration only and OCNGS: transparency. does not affect the technical adequacy of the PRA model.
1) A list of procedures reviewed, the potential pre-initiator actions associated with the procedures, and the disposition of the action (screened or evaluated).

Gap #8 Although this will not significantly impact the HRA HR-D3 Open. Possible upgrade to the pre-initiator This would be addressed by results, future PRA updates should include an HRA to include specific quantifications for each sensitivities per NEI 04-10 if applicable assessment of the quality of plant written procedures pre-initiator HEP would be strict compliance to the specific STI evaluation.

and administrative controls as well as human- with the standard. This is not considered machine interface for both pre-initiator and post- necessary for most applications.

initiator human actions.

LAR - Adoption of TSTF-425, Revision 3 Attachment 2 Docket No. 50-219 Page 9 of 16 Table 2-1 Status of Identified Gaps to Capability Category II of the ASME PRA Standard Title Description of Gap Applicable SRs Current Status / Comment Importance to Application Gap #9 Employ and document the methodology used for DA-C6 Open. A detailed determination is judged to Not significant. The PRA model is determining the standby component number of require a significant level of resources with judged to appropriately estimate the demands to include plant specific: marginal quantitative benefit. An estimate of number of demands for standby

1) surveillance tests the number of demands based on a review of equipment for calculating the failure surveillance tests and other means is judged to probabilities which will be acceptable
2) maintenance acts be sufficient. for most STI assessments.
3) surveillance tests or maintenance on other Additionally, the NEI 04-10 components methodology requires in Step 8 that an
4) operational demands appropriate time-related failure contribution be utilized in the STI
5) Additional demands from post-maintenance change assessment and Step 14 testing should not be included.

requires that sensitivity studies regarding the choice of that value be performed.

Gap #10 Failure data developed should be based on plant DA-C7 Partially resolved. The failure data was based Not significant. The PRA model is surveillance actual practices (as opposed to plant on actual plant data. However, the number of judged to appropriately estimate the requirements) and documented appropriately. demands and exposure data was based on number of demands for and exposure Currently based on system engineer experience actual data or estimates from the OCNGS time for calculating the component input. System Managers. failure probabilities Additionally, the NEI 04-10 methodology requires in Step 8 that an appropriate time-related failure contribution be utilized in the STI change assessment and Step 14 requires that sensitivity studies regarding the choice of that value be performed.

LAR - Adoption of TSTF-425, Revision 3 Attachment 2 Docket No. 50-219 Page 10 of 16 Table 2-1 Status of Identified Gaps to Capability Category II of the ASME PRA Standard Title Description of Gap Applicable SRs Current Status / Comment Importance to Application Gap #11 Standby failure data development should base the DA-C8 Open. A detailed determination is judged to Not significant. The PRA model is time that components were in standby on plant require a significant level of resources with judged to appropriately estimate the operational records. This should be documented marginal quantitative benefit. An estimate of time that components were in standby appropriately in the Component Data Notebook (OC the time that components were in standby is for calculating the standby failure rate.

PSA-010). judged to be sufficient. Additionally, the NEI 04-10 methodology requires in Step 8 that an appropriate time-related failure contribution be utilized in the STI change assessment and Step 14 requires that sensitivity studies regarding the choice of that value be performed.

Gap #12 Failure data development using surveillance test data DA-C10 Open. A detailed determination is judged to Not significant. The surveillance test should fulfill the requirements of DA-C10, and should require a significant level of resources with procedures are judged to address the be documented appropriately. Review surveillance marginal quantitative benefit. The surveillance appropriate failure modes with respect test procedures and identify all failure modes that are tests address the primary failure modes (e.g., to the estimated number of demands.

fully tested by the procedures. Include data for the pump fails to run or start, valve fails to Additionally, the NEI 04-10 failure modes that are fully tested. The results of open/close) in the PRA model. methodology requires in Step 8 that an unplanned demands on equipment should also be appropriate time-related failure accounted for. contribution be utilized in the STI change assessment and Step 14 requires that sensitivity studies regarding the choice of that value be performed.

Gap #13 No interviews of plant staff were performed to DA-C12 Open. This deviation from the SR is not Not significant because the model is generate uncertainty estimates of unavailability per considered to significantly alter the PRA consistent with data from the plant MR maintenance act. qualitative or quantitative results. database, so there will not be a An exception is taken to DA-C12. The plant staff significant impact on unavailability does not have reasonable insights applicable to the hours used in the model.

level of uncertainty associated with the maintenance durations. Most plant staff have rotated positions and do not have sufficient longevity to provide this insight.

LAR - Adoption of TSTF-425, Revision 3 Attachment 2 Docket No. 50-219 Page 11 of 16 Table 2-1 Status of Identified Gaps to Capability Category II of the ASME PRA Standard Title Description of Gap Applicable SRs Current Status / Comment Importance to Application Gap #14 Does not meet Capability Category II in that flood IF-A1a Open. Flood areas were not grouped Not significant. Changes to the flood areas were not defined at the level of individual according to the ASME Standard requirements. area groupings may create new flood rooms or combined rooms/halls for which plant The current grouping of flood areas captures initiating events with new associated design features exist to restrict flooding. For the risk significant scenarios. More detailed flood frequencies. However, the risk example, each elevation of the Reactor Building grouping is judged not to significantly impact significant flood scenarios and could be a different flood area because of the the flooding results. propagation paths are already different PRA impact or delay in flood propagation to appropriately modeled.

other areas allowing isolation of the flood source.

Gap #15 OCNGS does not have any significant internal flood IF-D5a Open. Determine how plant specific and Not significant. There are no plant events in their history up to the time when the internal generic operating experience can be specific flood events of the magnitude flood PRA was performed. incorporated into the internal flood pipe failure addressed in the PRA. Therefore, Gather plant specific data to estimate the pipe initiating event frequencies (e.g., impact of plant specific operating experience is lengths to calculate the flooding initiating event 2008 SW/ESW pipe leak event). judged to have a minor or negligible frequencies. impact on the calculated internal flood initiating events. The generic operating experience is the basis for the initiating event frequencies.

Gap #16 Strict reading of SR QU-F2 would indicate that the QU-F2 Partially Resolved With Open Item: The None. This is judged to be a following enhancements to the documentation of the documentation should include an overview of documentation consideration only and OCNGS PRA would need to be made to comply with the model integration and quantification does not affect the technical adequacy the Standard: process. A model integration process figure of the PRA model.

  • Incorporate an overview of the quantification can be included to show the information flow.

process. This should include the items cited in (c) of SR QU-F1 as well as a description of how the model files are integrated and used by the OCNGS input file.

  • Provide a list of human actions and equipment failures (significant basic events) that cause accidents to be non-dominant.

Gap #17 QU-F5 states to DOCUMENT limitations that would QU-F5 Open. Plant specific limitations are expected to None. The model limitations are impact applications. be well defined in response to QU-F4 (i.e., SR documented at various places within for documenting assumptions and sources of the multiple notebooks. One uncertainty). consolidated list is not provided. This is Discuss and document the limitations of the a documentation consideration only.

model as they relate to future applications.

(See QU-F4.).

LAR - Adoption of TSTF-425, Revision 3 Attachment 2 Docket No. 50-219 Page 12 of 16 Table 2-1 Status of Identified Gaps to Capability Category II of the ASME PRA Standard Title Description of Gap Applicable SRs Current Status / Comment Importance to Application Gap #18 Addendum B of the ASME PRA Standard [Ref. 6] QU-F6 Open - These new SRs will be addressed None. This is a documentation issue.

added SRs to document the quantitative definition during the next full PRA model update, but The model is not being changed to used for significant basic event, significant cutset, providing these definitions will not have an address this item.

significant accident sequence, and significant impact on the quantitative results from the PRA accident progression sequence in the CDF and LERF model.

analysis.

Gap #19 Addendum B of the ASME PRA Standard [Ref. 6] LE-G6 Open - These new SRs will be addressed None. This is a documentation issue.

added SRs to document the quantitative definition during the next full PRA model update, but The model is not being changed to used for significant basic event, significant cutset, providing these definitions will not have an address this item.

significant accident sequence, and significant impact on the quantitative results from the PRA accident progression sequence in the CDF and LERF model.

analysis.

LAR - Adoption of TSTF-425, Revision 3 Attachment 2 Docket No. 50-219 Page 13 of 16 2.3 External Events Considerations 2.3.1 IPEEE 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 can not 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 evaluated in the OCNGS Individual Plant Examination for 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 risks and was limited in its purpose to the identification of potential plant vulnerabilities and the understanding of associated severe accident risks.

The results of the OCNGS IPEEE study are documented in the OCNGS IPEEE Main Report

[Ref. 10]. Each of the OCNGS external event evaluations were reviewed by the NRC and compared to the requirements of NUREG-1407 [Ref. 11]. The NRC transmitted to Exelon (formerly GPU Nuclear Corporation) in 2001 their Staff Evaluation Report of the OCNGS IPEEE Submittal [Ref. 12].

Consistent with Generic Letter 88-20, the OCNGS IPEEE submittal does not screen out seismic or fire hazards, but provides quantitative analyses.

The seismic risk analysis provided in the OCNGS IPEEE (1995) is based on a detailed Seismic PRA. The internal fire events were originally addressed by using the EPRI Fire Induced Vulnerability Evaluation (FIVE) methodology [Ref. 13]. Subsequently, a plant specific Fire PRA was developed for OCNGS.

The OCNGS Seismic PRA study is a detailed analysis that, like the internal fire analysis, uses quantification and model elements (e.g., system fault trees, event tree structures, random failure rates, common cause failures, etc.) consistent with those employed in the internal events portion of the OCNGS Individual Plant Examination (IPE) study. However, OCNGS does not maintain its Seismic PRA current with the plant changes, procedure changes, and latest PRA model and methods.

In addition to internal fires and seismic events, the OCNGS IPEEE analysis of high winds or tornadoes, external floods, transportation accidents, aircraft impacts, nearby facility accidents, turbine missiles, and other external hazards was accomplished by reviewing the plant environs against regulatory requirements regarding these hazards. These hazards were screened from further analytic modeling and quantification.

2.3.2 Discussion of External Events Evaluation Seismic PRA The OCNGS Seismic PRA was developed as described in the IPEEE submittal. Some of the highlights of the OCNGS Seismic PRA methodology include the following:

LAR - Adoption of TSTF-425, Revision 3 Attachment 2 Docket No. 50-219 Page 14 of 16

  • Seismic fragilities based on EPRI site specific seismic hazard study. The revised Lawrence Livermore National Laboratory (LLNL) seismic hazard estimates are used as input as a sensitivity case.
  • A seismic event is not assumed to result in a Loss of Offsite Power (LOOP).

Seismic failure of offsite power is evaluated on a probabilistic basis according to component fragilities.

  • Most Balance of Plant equipment (e.g., Circulating Water, Service Water, Turbine Building Closed Cooling Water, Instrument Air, Feedwater, and Condensate) are modeled as guaranteed failure during a seismic event.

The OCNGS IPEEE states that no plant unique vulnerabilities associated with the Seismic Analysis were identified. As identified above, the Seismic PRA is not currently maintained for OCNGS. Thus, qualitative insights can be derived based on the Seismic IPEEE or a bounding quantitative assessment can be performed.

Fire PRA The OCNGS Fire IPEEE was developed as described in the IPEEE submittal [Ref. 10]. The OCNGS IPEEE states that no fire induced vulnerabilities were identified as a result of the analysis; therefore, no recommendation for further plant modifications are warranted.

Since the performance of the IPEEE, an updated Fire PRA model was developed in 2005 based on the 2004B Full Power Internal events PRA model. The 2005 Fire PRA model is judged to retain many conservatisms that existed in the IPEEE Fire PRA model. In addition, the 2005 Fire PRA has not undergone a PRA Peer Review; therefore, the OCNGS 2005 Fire PRA model is used in a limited manner to obtain additional insights for risk applications and provide qualitative and bounding quantitative assessments.

Another update to the OCNGS Fire PRA model is currently in progress based on the 2008A Internal Events PRA model. The in-progress OCNGS Fire PRA is an interim implementation of NUREG/CR-6850 [Ref. 14]; that is, not all tasks identified in NUREG/CR-6850 are yet completely addressed or implemented due to the changing state-of-the-art of industry at the time of the 2009 OCNGS Fire PRA development.

Other External Hazards The other external hazards are assessed to be non-significant contributors to plant risk:

  • Extreme Winds / Tornadoes: The OCNGS IPEEE study conservatively estimated the CDF from extreme wind and tornado hazards at a value of 5E-07/yr. The probability of wind speeds exceeding 168 mph is calculated to be 5E-7. Given wind speeds of this magnitude, all structures important to safety at OCNGS are conservatively assumed to fail.
  • Offsite / Transportation Hazards: The IPEEE identifies that the frequency of Transportation and Nearby Facility accidents is concluded to be acceptable low. Transportation and nearby hazards were screened from further consideration in the IPEEE.

LAR - Adoption of TSTF-425, Revision 3 Attachment 2 Docket No. 50-219 Page 15 of 16 conservative in that it assumes that a missile hit on critical structures or outdoor tanks will lead to a guaranteed core damage scenario.

  • Extreme Floods: The OCNGS site has a general grade elevation of 23 mean sea level (MSL). The Probable Maximum Hurricane (PMH) elevation at the site is 22 (MSL). The Probable Maximum Precipitation (PMP) results in a water level elevation at the site of 23.5 MSL.

As a result of the PMH and PMP flooding levels reported, the NRC identified nine (9) issues. These issues were identified based on a comparison to the Standard Review Plan (SRP) in effect at the time (1975 SRP). All of the issues have been considered resolved by the NRC as reported in the OCNGS Full-Term Operating License Safety Evaluation in 1991 [Ref. 15]. It is therefore concluded that the intent of the 1975 SRP criteria for the external flooding issue at OCNGS is met and no further analysis is required according to NUREG-1407.

2.3.3 Summary of External Event Status 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 bounding approach will be utilized in most cases. The fire PRA model will be exercised to obtain quantitative fire risk insights when a qualitative or a bounding analysis is not deemed sufficient, 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 OCNGS PRA technical capability evaluations and the maintenance and update processes described above provide a robust basis for concluding that the full power internal events OCNGS PRA is suitable for use in risk-informed processes such as that proposed for the implementation of a Surveillance Frequency Control Program. In performing the assessments for the other hazard groups, the qualitative or bounding approach will be utilized in most cases.

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.

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 (Draft), July 1996.

LAR - Adoption of TSTF-425, Revision 3 Attachment 2 Docket No. 50-219 Page 16 of 16

[4] Oyster Creek MSPI Basis Document, Rev. 0, March 2006.

[5] 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.

[6] 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.

[7] ASME Committee on Nuclear Risk Management in collaboration with ANS Risk Informed Standards Committee, Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications, ASME/ANS RA-Sa-2009, March 2009.

[8] Treatment of Parameter and Model Uncertainty for Probabilistic Risk Assessments, EPRI, Palo Alto, CA: December 2008 (Final). 1016737.

[9] NRC Generic Letter 88-20, Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities - 10 CFR 50.54(f), Supplement 4, June 28, 1991.

[10] GPU Nuclear Corporation, Oyster Creek Individual Plant Examination for External Events, Main Report, December 1995.

[11] NUREG-1407, Procedural and Submittal Guidance for the Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities, June 1991.

[12] Letter from Helen N. Pastis (USNRC) to Ronald Degregorio, AmerGen Energy Company, LLC, Review of Oyster Creek Nuclear Generating Station, (Oyster Creek),

Individual Plant Examination of External Events (IPEEE) Submittal (TAC No. M83652),

February 8, 2001 (Docket No. 50-219).

[13] Professional Loss Control, Inc., Fire-Induced Vulnerability Evaluation (FIVE)

Methodology Plant Screening Guide, EPRI TR-100370, Electric Power Research Institute, Final Report, April 1992.

[14] EPRI/NRC-RES, Fire PRA Methodology for Nuclear Power Facilities, EPRI 1011989, NUREG/CR-6850, Final Report, September 2005.

[15] Letter, January 29, 1991, from J. F. Stolz (NRC) to J. J. Barton (GPU Nuclear),

Subject:

Issuance of Safety Evaluation Report Relating to Full-Term Operating License for Oyster Creek Nuclear Generating Station.

ATTACHMENT 3 License Amendment Request Oyster Creek Nuclear Generating Station Docket No. 50-219 Application for Technical Specification Change Regarding Risk-Informed Justification for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program (Adoption of TSTF-425, Revision 3)

Proposed Technical Specification and Bases Page Changes i 4.1-8 4.4-2 4.5-14 4.10-1 iii 4.1-9 4.5-2 4.6-1 4.12-1 1.0-4 4.1-10 4.5-3 4.7-1 4.12-2 1.0-5 4.2-1 4.5-4 4.7-2 4.13-1 4.1-1 4.2-2 4.5-5 4.7-3 4.13-1a*

4.1-2 4.2-4 4.5-6 4.7-4 4.13-2 4.1-3 4.3-1 4.5-9 4.7-5 4.15-1 4.1-4 4.3-2 4.5-11 4.8-1 4.15-2 4.1-5 4.3-3 4.5-12 4.8-2 4.17-1 4.1-6 4.4-1 4.5-13 4.9-1 6-23 4.1-7

  • New page due to information rollover.

TABLE OF CONTENTS Section 1 Definitions Page 1.1 Operable - Operability 1.0-1 1.2 Operating 1.0-1 1.3 Power Operation 1.0-1 1.4 Startup Mode 1.0-1 1.5 Run Mode 1.0-1 1.6 Shutdown Condition 1.0-1 1.7 Cold Shutdown 1.0-2 1.8 Place in Shutdown Condition 1.0-2 1.9 Place in Cold Shutdown Condition 1.0-2 1.10 Place in Isolation Condition 1.0-2 1.11 Refuel Mode 1.0-2 1.12 Refueling Outage 1.0-2 1.13 Primary Containment Integrity 1.0-2 1.14 Secondary Containment Integrity 1.0-3 1.15 Deleted 1.0-3 1.16 Rated Flux 1.0-3 1.17 Reactor Thermal Power-To-Water 1.0-3 1.18 Protective Instrumentation Logic Definitions 1.0-3 1.19 Instrumentation Surveillance Definitions 1.0-4 1.20 FDSAR 1.0-4 1.21 Core Alteration 1.0-4 1.22 Critical Power Ratio 1.0-4 1.23 Staggered Test BasisDeleted 1.0-4 1.24 Surveillance Requirements 1.0-5 1.25 Appendix J Test Pressure 1.0-5 1.26 Fraction of Limiting Power Density (FLPD) 1.0-5 1.27 Maximum Fraction of Landing Power Density (MFLPD) 1.0-5 1.28 Fraction of Rated Power (FRP) 1.0-6 1.29 Top of Active Fuel (TAF) 1.0-6 1.30 Reportable Event 1.0-6 1.31 Identified Leakage 1.0-6 1.32 Unidentified Leakage 1.0-6 1.33 Process Control Plan 1.0-6 1.34 Augmented Offgas System (AOG) 1.0-6 1.35 Member of the Public 1.0-6 1.36 Offsite Dose Calculation Manual 1.0-6 1.37 Purge 1.0-7 1.39 Site Boundary 1.0-7 1.39 Reactor Vessel Pressure Testing 1.0-7 1.40 Substantive Changes 1.0-7 1.41 Dose Equivalent I-131 1.0-7 1.42 Average Planar Linear Heat Generation Rate 1.0-8 1.43 Core Operating Limits Report 1.0-8 OYSTER CREEK i Amendment No.: 161, 106, 205, 241

TABLE OF CONTENTS (cont'd)

Page 4.10 ECCs Related Core Limits 4.10-1 4.11 Sealed Source Contamination 4.11-1 4.12 Alternate Shutdown Monitoring Instrumentation 4.12-1 4.13 Accident Monitoring Instrumentation 4.13-1 4.14 DELETED 4.14-1 4.15 Explosive Gas Monitoring Instrumentation 4.15-1 4.16 (Deleted) 4.16-1 4.17 Control Room Heating, Ventilating and Air Conditioning System 4.17-1 Section 5 Design Features 5.1 Site 5.1-1 5.2 Containment 5.2-1 5.3 Auxiliary Equipment 5.3-1 Section 6 Administrative Controls 6.1 Responsibility 6-1 6.2 Organization 6-1 6.3 Facility Staff Qualifications 6-2a 6.4 DELETED 6-3 6.5 DELETED 6-3 6-6 Reportable Event Action 6-9 6-7 Safety Limit Violation 6-9 6-8 Procedures and Programs 6-10 6-9 Reporting Requirements 6-13 6-10 Record Retention 6-17 6-11 Radiation Protection Program 6-18 6-12 (Deleted) 6-18 6-13 High Radiation Area 6-18 6-14 Environmental Qualification 6-19*

6-15 Integrity of Systems Outside Containment 6-19 6-16 Iodine Monitoring 6-19 6-17 Post Accident Sampling 6-20 6-18 Process Control Plan 6-20 6-19 Offsite Dose Calculation Manual 6-20 6-20 DELETED 6-20 6-21 Technical Specification (TS) Bases Control Program 6-21 6-22 Control Room Envelope Habitability Program 6-21 6-23 Reactor Coolant System (RCS) PRESSURE AND TEMPERATURE LIMITS REPORT (PTLR) 6-22 6.24 Surveillance Frequency Control Program 6-23

  • Issued by NRC Order dated 10-24-80 OYSTER CREEK iii Amendment No.: 94, 97, 98, 108,115, 134, 166, 186, 232, 240, 241, 265, 269, 273

1.19 INSTRUMENTATION SURVEILLANCE DEFINITIONS A. CHANNEL CHECK A CHANNEL CHECK shall be the qualitative assessment, by observation, of channel behavior during operation. This determination shall include, where possible, comparison of the channel indication and status to other indications or status derived from independent instrument channels measuring the same parameter.

B. CHANNEL FUNCTIONAL TEST A CHANNEL FUNCTIONAL TEST shall be the injection of a simulated or actual signal into the channel as close to the sensor as practicable to verify OPERABILITY of all devices in the channel required for channel OPERABILITY. The CHANNEL FUNCTIONAL TEST may be performed by means of any series of sequential, overlapping, or total channel steps.

C. CHANNEL CALIBRATION A CHANNEL CALIBRATION shall be the adjustment, as necessary, of the channel output such that it responds within the necessary range and accuracy to known values of the parameter that the channel monitors. The CHANNEL CALIBRATION shall encompass all devices in the channel required for channel OPERABILITY and the CHANNEL FUNCTIONAL TEST. Calibration of instrument channels with resistance temperature detector (RTD) or thermocouple sensors may consist of an in place qualitative assessment of sensor behavior and normal calibration of the remaining adjustable devices in the channel. The CHANNEL CALIBRATION may be performed by means of any series of sequential, overlapping, or total channel steps.

D. Source Check A SOURCE CHECK is the qualitative assessment of channel response when the channel sensor is exposed to a source of radioactivity.

1.20 FDSAR Oyster Creek Unit No. 1 Facility Description and Safety Analysis Report as amended by revised pages and figure changes contained in Amendments 14, 31 and 45* and continuing through Amendment 79.

1.21 CORE ALTERATION A core alteration is the addition, removal, relocation or other manual movement of fuel or controls in the reactor core. Control rod movement with the control rod drive hydraulic system is not defined as a core alteration.

1.22 CRITICAL POWER RATIO The critical power ratio is the ratio of that power in a fuel assembly which is calculated, by application of an NRC approved CPR correlation, to cause some point in that assembly to experience boiling transition divided by the actual assembly operating power.

1.23 STAGGERED TEST BASIS(DELETED)

A Staggered Test Basis shall consist of:

A. A test schedule for n systems, subsystems, trains or other designated components obtained by dividing the specified test interval into n equal subintervals.

  • Per Erata dtd. 4-9-69 OYSTER CREEK 1.0-4 Amendment No.: 14, 108, 147, 211, 263

B. The testing of one system, subsystem, train or other designated component at the beginning of each subinterval.

1.24 SURVEILLANCE REQUIREMENTS Surveillance requirements are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within the safety limits, and that the limiting conditions of operation will be met. Each surveillance requirement shall be performed within the specified time interval 1

with a maximum allowable extension not to exceed 25% of the surveillance interval.

Surveillance requirements for systems and components are applicable only during the modes of operation for which the system or components are required to be operable, unless otherwise stated in the specification.

This definition establishes the limit for which the specified time interval for Surveillance Requirements may be extended. It permits an allowable extension of the normal surveillance interval to facilitate surveillance scheduling and consideration of plant operating conditions that may not be suitable for conducting the surveillance, e.g., transient conditions or other ongoing surveillance or maintenance activities. It also provides flexibility to accommodate the length of a fuel cycle for surveillances that are performed at each refueling outage and are specified with a fuel cycle length surveillance interval. It is not intended that this provision be used repeatedly as a convenience to extend surveillance intervals beyond that specified for the surveillance that are not performed during refueling outages. The limitation of this definition is based on engineering judgement and the recognition that the most probable result of any particular surveillance being performed is the verification of conformance with the Surveillance Requirements. This provision is sufficient to ensure that the reliability ensured through surveillance activities is not significantly degraded beyond that obtained from the specified surveillance interval.

1.25 APPENDIX J TEST PRESSURE For the purpose of conducting leak rate tests to meet 10 CFR 50 Appendix J, Pa = 35 psig.

1.26 FRACTION OF LIMITING POWER DENSITY (FLPD)

The fraction of limiting power density is the ratio of the linear heat generation rate (LHGR) existing at a given location to the design LHGR for that bundle type.

1.27 MAXIMUM FRACTION OF LIMITING POWER DENSITY (MFLPD)

The maximum fraction of limiting power density is the highest value existing in the core of the fraction of limiting power density (FLPD).

1 For the 10 CFR 50 Appendix J Type A test, the 25% shall not exceed 15 months.

OYSTER CREEK 1.0-5 Amendment No.: 161, 186

SECTION 4 SURVEILLANCE REQUIREMENTS 4.1 PROTECTIVE INSTRUMENTATION Applicability: Applies to the surveillance of the instrumentation that performs a safety function.

Objective: To specify the minimum frequency and type of surveillance to be applied to the safety instrumentation.

Specification: Instrumentation shall be checked, tested, and calibrated as indicated in Tables 4.1.1 and 4.1.2 using the definitions given in Section 1, and at the frequencies specified in the Surveillance Frequency Control Program unless otherwise noted in Tables 4.1.1 and 4.1.2.

OYSTER CREEK 4.1-1 Amendment No.: 171, 208

4.1 PROTECTIVE INSTRUMENTATION Bases:

Surveillance intervals are based on reliability analyses and have been determined in accordance with General Electric Licensing Topical Reports given in References 1 through 5.Surveillance intervals are based on operating experience, equipment reliability, and plant risk, and are controlled under the Surveillance Frequency Control Program (SFCP).

The functions listed in Table 4.1.1 logically divide into three groups:

a. On-off sensors that provide a scram function or some other equally important function.
b. Analog devices coupled with a bi-stable trip that provides a scram function or some other vitally important function.
c. Devices which only serve a useful function during some restricted mode of operation, such as startup or shutdown, or for which the only practical test is one that can be performed only at shutdown.

Group (b) devices utilize an analog sensor followed by an amplifier and bi-stable trip circuit. The sensor and amplifier are active components and a failure would generally result in an upscale signal, a downscale signal, or no signal. These conditions are alarmed so a failure would not go undetected. The bi-stable portion does need to be tested in order to prove that it will assume its tripped state when required.

Group (c) devices are active only during a given portion of the operational cycle. For example, the IRM is inactive during full-power operation and active during startup. Thus, the only test that is significant is the one performed just prior to shutdown and startup. The condenser Low Vacuum trip can only be tested during shutdown, and although it is connected into the reactor protection system, it is not required to protect the reactor. Testing at each REFUELING OUTAGEin accordance with the Surveillance Frequency Control Program (SFCP) is adequate. The switches for the high temperature main steamline tunnel are not accessible during normal operation because of their location above the main steam lines. Therefore, after initial calibration and in-place OPERABILITY checks, they will not be tested between refueling shutdowns. Considering the physical arrangement of the piping which would allow a steam leak at any of the four sensing locations to affect the other locations, it is considered that the function is not jeopardized by limiting calibration and testing to refueling outages.

The CHANNEL FUNCTIONAL TEST verifies instrument channel operability. A successful test of the required contact(s) of a channel relay may be performed by the verification of a change in state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST or CHANNEL CALIBRATION of a relay. This is acceptable because all the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specification tests.

The logic of the instrument safety systems in Table 4.1.1 is such that testing the instrument channels trips the trip system to verify that it is OPERABLE. The testing may be performed by means of any series of sequential, overlapping, or total channel steps. However, certain systems require coincident instrument channel trips to completely test their trip systems. Therefore, SFCP Table 4.1.2 specifies the minimum trip system test frequency for these tripped systems. This assures that all trip systems for protective instrumentation are adequately tested, from sensors through the trip system.

OYSTER CREEK 4.1-2 Amendment No.: 171, 208, 263

IRM calibration is to be performed during reactor startup. The calibration of the IRMs during startup will be significant since the IRMs will be relied on for neutron monitoring and reactor protection up to 38.4% of rated power during a reactor startup.

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. Limiting Safety System Settings (LSSS) 2.3.A.1 allows the APRMs to be reading greater than actual THERMAL POWER to compensate for localized power peaking. When this adjustment is made, the requirement for the absolute difference between the APRM channels and the calculated power to indicate within 2%

RTP is modified to include any gain adjustments required by LSSS 2.3.A.1.

LPRM gain settings are determined from the local flux profiles measured by the Traversing Incore Probe (TIP) System. This establishes the relative local flux profile for appropriate representative input to the APRM System. The 1000 MWD/T Frequency specified in the Surveillance Frequency Control Program is based on operating experience with LPRM sensitivity changes.

General Electric Licensing Topical Report NEDC-30851P-A (Reference 1), Section 5.7 indicates that the major contributor to reactor protection system unavailability is common cause failure of the automatic scram contactors. Analysis showed a weekly test interval to be optimum for Scram contactors are tested in accordance with the Surveillance Frequency Control Program. The test of the automatic scram contactors can be performed as part of the CHANNEL CALIBRATION or CHANNEL FUNCTIONAL TEST of Scram Functions or by use of the subchannel test switches.

References:

(1) NEDC-30851P-A, "Technical Specification Improvement Analyses for BWR Reactor Protection System."

(2) NEDC-30936P-A, "BWR Owners' Group Technical Specification Improvement Methodology (With Demonstration for BWR ECCS Actuation Instrumentation)," Parts 1 and 2.

(3) NEDC-30851P-A, Supplement 1, "Technical Specification Improvement Analysis for BWR Control Rod Block Instrumentation."

(4) NEDC-30851P-A, Supplement 2, "Technical Specification Improvement Analysis for BWR Isolation Instrumentation Common to RPS and ECCS Instrumentation."

(5) NEDC-31677P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation."

OYSTER CREEK 4.1-3 AMENDMENT NO.: 71,171, 208, 263, 266

TABLE 4.1.1 Page 1 of 6 MINIMUM CHECK, CALIBRATION AND TEST FREQUENCY FOR PROTECTIVE INSTRUMENTATION Instrument Channel Check (Note 5) Calibrate (Note 5) Test (Note 5) Remarks (Applies to Test & Calibration)

1. High Reactor Pressure 1/d Note 3 1/3 mo.
2. High Drywell Pressure (Scram) N/A 1/3 mo. 1/3 mo. By application of test pressure
3. Low Reactor Water Level 1/d Note 3 1/3 mo.
4. Low-Low Water Level 1/d Note 3 1/3 mo.
5. High Water Level in Scram Discharge Volume
a. Digital N/A 1/3 mo. 1/3 mo. By varying level in sensor columns
b. Analog N/A Note 3 1/3 mo.
6. Low-Low-Low Water Level N/A 1/3 mo. 1/3 mo. By application of test pressure
7. High Flow in Main Steamline 1/d 1/3 mo. 1/3 mo. By application of test pressure
8. Low Pressure in Main Steamline N/A 1/3 mo. 1/3 mo. By application of test pressure
9. High Drywell Pressure (Core Cooling) 1/d 1/3 mo. 1/3 mo. By application of test pressure
10. Main Steam Isolation Valve (Scam) N/A N/A 1/3 mo. By exercising valve OYSTER CREEK 4.1-4 Change: 7. Amendment No.: 152, 171, 208

TABLE 4.1.1 Page 2 of 6 MINIMUM CHECK, CALIBRATION AND TEST FREQUENCY FOR PROTECTIVE INSTRUMENTATION Instrument Channel Check (Note 5) Calibrate (Note 5) Test (Note 5) Remarks (Applies to Test & Calibration)

11. APRM Level N/A 1/3d N/A Verify the absolute difference between the APRM channels and the calculated power is 2% rated thermal power [plus any gains required by LSSS 2.3.A.1]

APRM Scram Trips Note 2 1/3 mo. 1/3 mo. Using built-in calibration equipment

  • Flow based neutron flux - high During POWER OPERATION
  • Fixed neutron flux - high or inop
  • Downscale
12. APRM Rod Blocks Note 2 1/3 mo. 1/3 mo. Upscale and downscale
13. DELETED
14. High Radiation in Reactor Building Operating Floor 1/s 1/3 mo. 1/3 mo. Using gamma source for calibration Ventilation Exhaust 1/s 1/3 mo. 1/3 mo.
15. High Radiation on Air Ejector Off-Gas 1/3 mo. 1/3 mo. Using built-in calibration equipment 1/s Channel Check 1/mo. Source check 1/24 mo. Calibration according to established station calibration procedures 1/24 mo. Note a OYSTER CREEK 4.1-5 Change: 7, Amendment No.: 108, 141, 171, 208

TABLE 4.1.1 Page 3 of 6 MINIMUM CHECK, CALIBRATION AND TEST FREQUENCY FOR PROTECTIVE INSTRUMENTATION Instrument Channel Check (Note 5) Calibrate(Note 5) Test (Note 5) Remarks (Applies to Test & Calibration)

16. IRM Level N/A Each Startup N/A IRM Scram * *
  • Using built-in calibration equipment
17. IRM Blocks N/A Prior to startup Prior to startup Upscale and downscale and shutdown and shutdown
18. Condenser Low Vacuum N/A 1/24 mo. 1/24 mo.
19. Manual Scram Buttons N/A N/A 1/3 mo.
20. High Temperature Main Steamline Tunnel N/A 1/24 mo. Each refueling Using heat source box outage
21. SRM * *
  • Using built-in calibration equipment
22. Isolation Condenser High Flow P (Steam & N/A 1/3 mo. 1/3 mo. By application of test pressure Water)
23. Turbine Trip Scram N/A N/A 1/3 mo.
24. Generator Load Rejection Scram N/A 1/3 mo. 1/3 mo.
25. Recirculation Loop Flow N/A 1/24 mo. N/A By application of test pressure
26. Low Reactor Pressure Core Spray Valve N/A 1/3 mo. 1/3 mo. By application of test pressure Permissive OYSTER CREEK 4.1-6 Change: 7, Amendment No.: 71, 144, 193, 208

TABLE 4.1.1 Page 4 of 6 MINIMUM CHECK, CALIBRATION AND TEST FREQUENCY FOR PROTECTIVE INSTRUMENTATION Instrument Channel Check (Note 5) Calibrate (Note 5) Test (Note 5) Remarks (Applies to Test & Calibration)

27. Scram Discharge Volume (Rod Block) a) Water level high N/A Each refueling 1/3 mo. Calibrate by varying level in sensor outage column b) Scram Trip bypass N/A N/A Each refueling outage
28. Loss of Power a) 4.16 KV Emergency Bus Undervoltage 1/d 1/24 mo. 1/mo.

(Loss of Voltage) b) 4.16 KV Emergency Bus Undervoltage 1/d 1/24 mo. 1/mo.

(Degraded Voltage)

29. Drywell High Radiation N/A Each refueling Each refueling outage outage
30. Automatic Scram Contactors N/A N/A 1/wk Note 1
31. Core Spray Booster Pump Differential N/A 1/3 mo. 1/3 mo. By application of a test pressure Pressure OYSTER CREEK 4.1-7 Change: 7, Amendment No.: 63,80,116,141,144,152,171,190, 208

TABLE 4.1.1 Page 5 of 6 MINIMUM CHECK, CALIBRATION AND TEST FREQUENCY FOR PROTECTIVE INSTRUMENTATION Instrument Channel Check (Note 5) Calibrate (Note 5) Test (Note 5) Remarks (Applies to Test & Calibration)

32. LPRM Level a) Electronics N/A 1/12 mo. 1/12 mo.

b) Detectors N/A Note 4 N/A

33. RWCU HELB High Temperature N/A Each refueling 1/3 mo. Perform Channel Tests using the test outage switches.

Legend: N/A = Not Applicable 1/s = Once per shift 1/d = Once per day 1/3d = Once per 3 days 1/wk = Once per week 1/mo. = Once per month 1/3 mo. = Once every three months 1/12 mo. = Once every 12 months 1/24 mo. = Once every 24 months OYSTER CREEK 4.1-8 Change: 7, Amendment No.: 171, 208, 259

TABLE 4.1.1 Page 6 of 6 MINIMUM CHECK, CALIBRATION AND TEST FREQUENCY FOR PROTECTIVE INSTRUMENTATION NOTE 1: Each automatic scram contactor is required to be tested at least once per week in accordance with the Surveillance Frequency Control Program. When not tested by other means, the weekly test can be performed by using the subchannel test switches.

NOTE 2: At least daily during reactor POWER OPERATIONIn accordance with the Surveillance Frequency Control Program, the reactor neutron flux peaking factor shall be estimated and flow-referenced APRM scram and rod block settings shall be adjusted, if necessary, as specified in Section 2.3 Specifications A.1 and A.2.

NOTE 3: Calibrate electronic bistable trips by injection of an external test current in accordance with the Surveillance Frequency Control Programonce per 3 months. Calibrate transmitters by application of test pressure in accordance with the Surveillance Frequency Control Programonce per 12 months.

NOTE 4: Perform LPRM detectors calibration in accordance with the Surveillance Frequency Control Program.every 1000 MWD/MT Average Core Exposure NOTE 5: Surveillance intervals are specified in the Surveillance Frequency Control Program unless otherwise noted in the table.

The following notes are only for Item 15 of Table 4.1.1:

A channel may be taken out of service for the purpose of a check, calibration, test or maintenance without declaring the channel to be inoperable.

a. The CHANNEL FUNCTIONAL TEST shall also demonstrate that control room alarm annunciation occurs if any of the following conditions exists:
1) Instrument indicates measured levels above the alarm setpoint.
2) Instrument indicates a downscale failure.
3) Instrument controls not set in operate mode.
4) Instrument electrical power loss.

OYSTER CREEK 4.1-9 Change: 5, 7, Amendment No.: 71, 80, 95, 108, 171, 208, 263, 273

TABLE 4.1.2 MINIMUM TEST FREQUENCIES FOR TRIP SYSTEMS Trip System Minimum Test Frequency (Note 1)

1) Dual Channel (Scram) Same as for respective Instrumentation in Table 4.1.1
2) Rod Block Same as for respective Instrumentation in Table 4.1.1
3) DELETED DELETED
4) Automatic Depressurization Each refueling outage each trip system, one at a time
5) MSIV Closure Each refueling outage each closure logic circuit independently (1 valve at a time)
6) Core Spray 1/3 mo and each refueling outage each trip system, one at a time
7) Primary Containment Isolation Each refueling outage each trip circuit independently (1 valve at a time)
8) Refueling Interlocks Prior to each refueling operation
9) Isolation Condenser Actuation and Isolation Each refueling outage each trip circuit independently (1 valve at a time)
10) Reactor Building Isolation and SGTS Same as for respective Instrumentation Initiation in Table 4.1.1
11) DELETED DELETED
12) Air Ejector Offgass Line Isolation Each refueling outage
13) Containment Vent and Purge Isolation 1/24 mo Note 1: Surveillance intervals are specified in the Surveillance Frequency Control Program unless otherwise noted in the table.

OYSTER CREEK 4.1-10 Amendment No.: 108,116,144,160,171,193, 208, 273

4.2 REACTIVITY CONTROL Applicability: Applies to the surveillance requirements for reactivity control.

Qbjective: To verify the capability for controlling reactivity.

Specification:

A. SDM shall be verified:

1. Prior to each CORE ALTERATION, and
2. Once within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> following the first criticality following any CORE ALTERATION.

B. The control rod drive housing support system shall be inspected after reassembly.

C. The maximum scram insertion time of the control rods shall be demonstrated through measurement and, during single control rod scram time tests, the control rod drive pumps shall be isolated from the accumulators:

1. For all control rods prior to THERMAL POWER exceeding 40% power with reactor coolant pressure greater than 800 psig, following core alterations or after a reactor shutdown that is greater than 120 days.
2. For specifically affected individual control rods following maintenance on or modification to the control rod or control rod drive system which could affect the scram insertion time of those specific control rods in accordance with either a or b as follows:

a.1 Specifically affected individual control rods shall be scram time tested with the reactor depressurized and the scram insertion time from the fully withdrawn position to 90% insertion shall not exceed 2.2 seconds, and a.2 Specifically affected individual control rods shall be scram time tested at greater than 800 psig reactor coolant pressure prior to exceeding 40% power.

b. Specifically affected individual control rods shall be scram time tested at greater than 800 psig reactor coolant pressure.
3. On a frequency of less than or equal to once per 180 days of cumulative power operationIn accordance with the Surveillance Frequency Control Program, for at least 20 control rods, on a rotating basis, with reactor coolant pressure greater than 800 psig.

D. Each partially or fully withdrawn control rod shall be exercised at least once per 31 daysin accordance with the Surveillance Frequency Control Program.

This test shall be performed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in the event power operation is continuing with two or more inoperable control rods or in the event power operation is continuing with one fully or partially withdrawn rod which cannot be moved and for which control rod drive mechanism damage has not been ruled out. The surveillance need not be completed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> if the number of inoperable rods has been reduced to less than two and if it has been demonstrated that control rod drive mechanism collet housing failure is not the cause of an immovable control rod.

OYSTER CREEK 4.2-1 Amendment No: 178, 198, 249, 266, 275

E. Surveillance of the standby liquid control system shall be as follows:

1. Pump operability Note 1Once/3 months
2. Boron concentration Note 1Once/month determination
3. Functional test Note 1Once every 24 months
4. Solution volume and Note 1Once/day temperature check
5. Solution Boron-10 Note 1Once every 24 months.

Enrichment Enrichment analyses shall be received no later than 30 days after sampling. If not received within 30 days, notify NRC (within 7 days) of plans to obtain test results.

Note 1: Surveillance intervals are specified in the Surveillance Frequency Control Program unless otherwise noted above.

F. At specific power operation conditions, the actual control rod configuration will be compared with the expected configuration based upon appropriately corrected past data. This comparison shall be made every equivalent full power month. The initial rod inventory measurement performed with equilibrium conditions are established after a refueling or major core alteration will be used as base data for reactivity monitoring during subsequent power operation throughout the fuel cycle.

G. The scram discharge volume drain and vent valves shall be verified open at least once per 31 daysin accordance with the Surveillance Frequency Control Program, except in shutdown mode*, and shall be cycled at least one complete cycle of full travel in accordance with the Surveillance Frequency Control Programat least quarterly.

H. All withdrawn control rods shall be determined OPERABLE by demonstrating the scram discharge volume drain and vent valves OPERABLE. This will be done in accordance with the Surveillance Frequency Control Programat least once per refueling cycle by placing the mode switch in shutdown and by verifying that:

a. The drain and vent valves close within 30 seconds after receipt of a signal for control rods to scram, and
b. The scram signal can be reset and the drain and vent valves open when the scram discharge volume trip is bypassed.
  • These valves may be closed intermittently for testing under administrative control.

Corrected: 12/24/84 OYSTER CREEK 4.2-2 Amendment No.: 64, 74, 75,124,141,159, 172, 178 Change: 25

The weekly control rod exercise test in accordance with the Surveillance Frequency Control Program serves as a periodic check against deterioration of the control rod system. Experience with this control rod system has indicated that weekly tests are adequate, and that rods which move by drive pressure will scram when required as the pressure applied is much higher. The requirement to exercise the control rods within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of a condition with two or more control rods which are valved out of service or one fully or partially withdrawn control rod which can not be moved provides assurance of the reliability of the remaining control rods.

Pump operability, boron concentration, solution temperature and volume (4) of standby liquid control system are checked on a frequency consistent with instrumentation checks described in Specification 4.1 in accordance with the Surveillance Frequency Control Program.

Experience with similar systems has indicated that the test frequencies are adequate. The only practical time to functionally test the liquid control system is during a refueling outage. The functional test includes the firing of explosive charges to open the shear plug valves and the pumping of demineralized water into the reactor to assure operability of the system downstream of the pumps. The test also includes recirculation of liquid control solution to and from the solution tanks.

Pump operability is demonstrated on a more frequent basis. This test consists of recirculation of demineralized water to a test tank. A continuity check of the firing circuit on the shear plug valves is provided by pilot lights in the control room. Tank level and temperature alarms are provided to alert the operator to off-normal conditions.

Figure 3.2.1 was revised to reflect the minimum and maximum weight percent of sodium pentaborate solution, and the minimum atom percent of B-10 to meet 10 CFR 50.62(c)(4). Since the weight percent of sodium pentaborate can change with water makeup or water evaporation, frequent surveillances are performed on the solution concentration, volume and temperature. The sodium pentaborate is enriched with B-10 at the chemical vendor's facility to meet the minimum atom percent.

Preshipment samples of batches are analyzed for B-10 enrichment and verified by an independent laboratory prior to shipment to Oyster Creek. Since the B-10 enrichment will not change while in storage or in the SLCS tank, the surveillance for B-10 enrichment is performed on a 24 month intervalin accordance with the Surveillance Frequency Control Program. An additional requirement has been added to evaluate the solution's capability to meet the original design shutdown criteria whenever the Boron-10 enrichment requirement is not met.

The functional test and other surveillance on components, along with the monitoring instrumentation, gives a high reliability for standby liquid control system operability.

References (1) FDSAR, Volume II, Figure III-5-11 (2) FDSAR, Volume I, Section VI-3 (3) FDSAR, Volume I, Section III-5 and Volume II, Appendix B (4) FDSAR, Volume I, Section VI-4 OYSTER CREEK 4.2-4 Amendment No.: 75, 124, 159, 172, 178

4.3 REACTOR COOLANT Applicability: Applies to the surveillance requirements for the reactor coolant system.

Objective: To determine the condition of the reactor coolant system and the operation of the safety devices related to it.

Specification: A. Materials surveillance specimens and neutron flux monitors shall be installed in the reactor vessel adjacent to the wall at the midplane of the active core.

Specimens and monitors shall be periodically removed, tested, and evaluated to determine the effects of neutron fluence on the fracture toughness of the vessel shell materials. Pressure and temperature curves are contained in the Pressure and Temperature Limits Report (PTLR).

B. Inservice inspection of ASME Code Class 1, Class 2 and Class 3 systems and components shall be performed in accordance with Section XI of the ASME Boiler and Pressure Vessel Code and applicable Addenda as required by 10 CFR, Section 50.55a, except where specific written relief has been granted by the NRC pursuant to 10 CFR, Section 50.55a.

C. Inservice testing of ASME Code Class 1, Class 2 and Class 3 pumps and valves shall be performed in accordance with the ASME Code for Operation and Maintenance of Nuclear Power Plants (ASME OM Code) and applicable Addenda as required by 10 CFR, Section 50.55a, except where specific written relief has been granted by the NRC pursuant to 10 CFR, Section 50.55a.

D. A visual examination for leaks shall be made with the reactor coolant system at pressure during each scheduled refueling outage or after major repairs have been made to the reactor coolant system in accordance with Article 5000,Section XI. The requirements of specification 3.3.A shall be met during the test.

E. Each replacement safety valve or valve that has been repaired shall be tested in accordance with Specification C above. Setpoints shall be as follows:

Number of Valves Set Points (psig) 4 1212 +/- 36 5 1221 +/- 36 F. A sample of reactor coolant shall be analyzed at least every 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />sin accordance with the Surveillance Frequency Control Program for the purpose of determining the content of chloride ion and to check the conductivity.

OYSTER CREEK 4.3-1 Amendment No.: 82, 90, 120, 150, 151, 164, 188, 195, 261, 268, 269

  • G. Primary Coolant System Pressure Isolation Valves Specification:

(a)

1. Periodic leakage testing on each valve listed in Table 4.3.1 shall be accomplished prior to exceeding 600 psig reactor pressure every time the plant is placed in the cold shutdown condition for refueling, each time the plant is placed in a cold shutdown condition for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> if testing has not been accomplished in the preceding 9 months, whenever the valve is moved whether by manual actuation or due to flow conditions, and after returning the valve to service after maintenance, repair or replacement work is performed.

H. Reactor Coolant System Leakage

1. Unidentified leakage rate shall be calculated in accordance with the Surveillance Frequency Control Programat least once every 4hours.
2. Total leakage rate (identified and unidentified) shall be calculated in accordance with the Surveillance Frequency Control Programat least once every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
3. A CHANNEL CALIBRATION of the primary containment sump flow integrator and the primary containment equipment drain tank flow integrator shall be conducted in accordance with the Surveillance Frequency Control Programat least once per 24 months.

I. An inservice inspection program for piping identified in NRC Generic Letter 88-01 shall be performed in accordance with the NRC staff positions on schedule, methods, personnel, and sample expansion included in the generic letter or in accordance with alternate measures approved by the NRC staff.

Bases:

Data is available relating neutron fluence (E>1.0MeV) and the change in the Reference Nil-Ductility Transition Temperature (RTNDT). Pressure and temperature curves are contained in the Pressure and Temperature Limits Report (PTLR).

The inspection program will reveal problem areas should they occur, before a leak develops. In addition, extensive visual inspection for leaks will be made on critical systems. Oyster Creek was designed and constructed prior to (a)

To satisfy ALARA requirements, leakage may be measured indirectly (as from the performance of pressure indicators) if accomplished in accordance with approved procedures and supported by computations showing that the method is capable of demonstrating valve compliance with the leakage criteria.

  • NRC Order dated April 20, 1981.

OYSTER CREEK 4.3-2 Amendment No.: 97,118,120,151,154, 188, 193, 263, 269

the existence of ASME Section XI. For this reason, the degree of access required by ASME Section XI is not generally available and will be addressed as "requests for relief in accordance with 10 CFR 50.55a(g).

Experience in safety valve operation shows testing in accordance with the ASME Code is adequate to detect failures or deterioration. The as-found setpoint tolerance is specified in the ASME OM Code as the owner-defined tolerance or +/- 3% of valve nameplate set pressure. An analysis has been performed which shows that with all safety valves set 36 psig higher, the safety limit of 1375 psig is not exceeded.

Conductivity instruments continuously monitor the reactor coolant. Experience indicates that a periodic check of the conductivity instrumentation at least every 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />sin accordance with the Surveillance Frequency Control Program is adequate to ensure accurate readings. The reactor water sample will also be used to determine the chloride ion content to assure that the limits of 3.3.E are not exceeded. The chloride ion content will not change rapidly over a period of several days; therefore, the sampling frequency is adequate.

OYSTER CREEK 4.3-3 Amendment No.: 82, 90, 261, 268

4.4 EMERGENCY COOLING Applicability: Applies to surveillance requirements for the emergency cooling systems.

Objective: To verify the operability of the emergency cooling systems.

Specification: Surveillance of the emergency cooling systems shall be performed as follows:

Item Frequency A. Core Spray System

1. Pump Operability Note 1Once/3 months. Also after major maintenance and prior to startup following a refueling outage.
2. Motor operated valve Note 1Once/3 months operability
3. Automatic actuation test Note 1Every three months
4. Pump compartment water- Note 1Once/week and after each entry tight doors closed
5. Core spray header P instrumentation CHANNEL CHECK Note 1Once/day CHANNEL CALIBRATION Note 1Once/3 months CHANNEL FUNCTIONAL TEST Note 1Once/3 months B. Automatic Depressurization
1. Verify each relief valve actuator Note 1Once every 24 months strokes when manually actuated
2. Automatic actuation test Note 1Every refueling outage C. Containment Cooling System
1. Pump Operability Note 1Once/3 months. Also after major maintenance and prior to startup following a refueling outage.

OYSTER CREEK 4.4-1 Amendment No. 109,144,193, 210, 260,263

Item Frequency C. Containment Cooling System

2. Motor-operated valve operability Note 1Every 3 months
3. Pump compartment water- Note 1Once/week and after each entry tight doors closed D. Emergency Service Water System
1. Pump Operability Note 1Once/3 months. Also after major maintenance and prior to startup following a refueling outage.

E. Control Rod Drive Hydraulic System

1. Pump Operability Note 1Once/month. Also after major maintenance and prior to startup following a refueling outage.

F. Fire Protection System

1. Pump Operability Note 1Once/month. Also after major maintenance and prior to startup following a refueling outage.
2. Isolation valve operability Note 1Once/3 months. Also after major maintenance and prior to startup following a refueling outage.

Note 1: Surveillance intervals are specified in the Surveillance Frequency Control Program unless otherwise noted.

Bases:

It is during major maintenance or repair that a system's design intent may be violated accidentally.

Therefore, a functional test is required after every major maintenance operation. During an extended outage, such as a refueling outage, major repair and maintenance may be performed on many systems. To be sure that these repairs on other systems do not encroach unintentionally on critical standby cooling systems, they should be given a functional test prior to startup.

Motor operated pumps, valves and other active devices that are normally on standby should be exercised periodically to make sure that they are free to operate. Motors on pumps should operate long enough to approach equilibrium temperature to ensure there is no overheat problem.

Whenever practical, valves should be stroked full length to ensure that nothing impedes their motion. Testing of components per OC Inservice Testing Program in accordance with the ASME Code once every 3 months provides assurances of the availability of the system. The Control Rod Hydraulic pumps and Fire Protection System pumps are not part of the Inservice Test Program per the ASME Code and will continue to be tested for operability once per monthin accordance with the Surveillance Frequency Control Program. Engineering judgment based on experience and availability analyses of the type presented in Appendix L of the FDSAR indicates that testing these components more often than once a month over a long period of time does not significantly improve the system reliability. Also, at this frequency of testing wearout should not be a problem through the life of the plant.

OYSTER CREEK 4.4-2 Amendment No.: 109,160, 210, 268

b. If the airlock is opened during a period when Primary Containment is not required, it need not be tested while Primary Containment is not required, but must be tested at Pa prior to returning the reactor to an operating mode requiring PRIMARY CONTAINMENT INTEGRITY.

D. Primary Containment Leakage Rates shall be limited to:

1. The maximum allowable Primary Containment leakage rate is 1.0 La. The maximum allowable Primary Containment leakage rate to allow for plant startup following a type A test is 0.75 La. The leakage rate acceptance criteria for the Primary Containment Leakage Rate Testing Program for Type B and Type C tests is 0.60 La at Pa, except as stated in Specification 4.5.D.2.
2. Verify leakage rate through each MSIV is 11.9 scfh when tested at 20 psig.
3. The leakage rate acceptance criteria for the drywell airlock shall be 0.05 La when measured or adjusted to Pa.

E. Continuous Leak Rate Monitor

1. When the primary containment is inerted, the containment shall be continuously monitored for gross leakage by review of the inerting system makeup requirements.
2. This monitoring system may be taken out of service for the purpose of maintenance or testing but shall be returned to service as soon as practical.

F. Functional Test of Valves

1. All automatic primary containment isolation valves shall be tested for automatic closure by an isolation signal in accordance with the Surveillance Frequency Control Programduring each REFUELING OUTAGE and the isolation time determined to be within its limit. The following valves are required to close in the time specified below:

Main steam line isolation valves: 3 seconds and 10 seconds

2. Each automatic primary containment isolation valve shall be demonstrated OPERABLE prior to returning the valve to service after maintenance, repair or replacement work is performed on OYSTER CREEK 4.5-2 Amendment No.: 132, 186, 196, 250

the valve or its associated actuator by cycling the valve through at least one complete cycle of full travel and verifying the isolation time limit is met.

Following maintenance, repair or replacement work on the control or power circuit for the valves, the affected component shall be tested to assure it will perform its intended function in the circuit.

3. During each COLD SHUTDOWN, each main steam isolation valve shall be closed and its closure time verified to be within the limits of Specification 4.5.F.1 above unless this test has been performed within the last 92 days.
4. Reactor Building to Suppression Chamber Vacuum Breakers
a. The reactor building to suppression chamber vacuum breakers and associated instrumentation, including setpoint, shall be checked for proper operation in accordance with the Surveillance Frequency Control Programevery three months.
b. In accordance with the Surveillance Frequency Control ProgramDuring each REFUELING OUTAGE, each vacuum breaker shall be tested to determine that the force required to open the vacuum breaker from closed to fully open does not exceed the force specified in Specification 3.5.A.4.a. The air-operated vacuum breaker instrumentation shall be calibrated in accordance with the Surveillance Frequency Control Programduring each REFUELING OUTAGE.
5. Pressure Suppression Chamber - Drywell Vacuum Breakers
a. Periodic OPERABILITY Tests In accordance with the Surveillance Frequency Control ProgramOnce every 3 months and following any release of energy which would tend to increase pressure to the suppression chamber, each OPERABLE suppression chamber - drywell vacuum breaker shall be exercised.

Operation of position switches, indicators and alarms shall be verified in accordance with the Surveillance Frequency Control Programevery 3 months by operation of each OPERABLE vacuum breaker.

b. REFUELING OUTAGE TestsThe following tests, with the exception of b(4),

are performed in accordance with the Surveillance Frequency Control Program.

(1) All suppression chamber - drywell vacuum breakers shall be tested to determine the force required to open each valve from fully closed to fully open.

(2) The suppression chamber - drywell vacuum breaker position indication and alarm systems shall be calibrated and functionally tested.

OYSTER CREEK 4.5-3 Amendment No.: 144, 186, 196, 210,221

(3) At least four of the suppression chamber - drywell vacuum breakers shall be inspected. If deficiencies are found, all vacuum breakers shall be inspected and deficiencies corrected such that Specification 3.5.A.5.a can be met.

(4) A drywell to suppression chamber leak rate test shall be performed once every 24 months to demonstrate that with an initial differential pressure of not less than 1.0 psi, the differential pressure decay rate shall not exceed the equivalent of air flow through a 2-inch orifice.

G. Reactor Building

1. Secondary containment capability tests shall be conducted after isolating the reactor building and placing either Standby Gas Treatment System filter train in operation.
2. The tests shall be performed in accordance with the Surveillance Frequency Control Programat least once per operating cycle (interval not to exceed 20 months) and shall demonstrate the capability to maintain a 1/4 inch of water vacuum under calm wind conditions with a Standby Gas Treatment System Filter train flow rate of not more than 4000cfm.
3. A secondary containment capability test shall be conducted at each refueling outage prior to refueling.
4. The results of the secondary containment capability tests shall be in the subject of a summary technical report which can be included in the reports specified in Section 6.

H. Standby Gas Treatment System

1. The capability of each Standby Gas Treatment System circuit shall be demonstrated by:
a. In accordance with the Surveillance Frequency Control ProgramAt least once per 18 months, after every 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of operation, and following significant painting, fire, or chemical release in the reactor building during operation of the Standby Gas Treatment System by verifying that:

(1) The charcoal absorbers remove 99% of a halogenated hydrocarbon refrigerant test gas and the HEPA filters remove 99% of the DOP in a cold DOP test when tested in accordance with ANSI N510-1975.

OYSTER CREEK 4.5-4 Amendment No.: 144,186,193,219

(2) Results of laboratory carbon sample analysis show 95%

radioactive methyl iodide removal efficiency when tested in accordance with ASTM D 3803-1989 (30°C, 95% relative humidity, at least 45.72 feet per minute charcoal bed face velocity).

b. In accordance with the Surveillance Frequency Control ProgramAt least once per 18 months by demonstrating:

(1) That the pressure drop across a HEPA filter is equal to or less than the maximum allowable pressure drop indicated in Figure 4.5.1.

(2) The inlet heater is capable of at least 10.9 KW input.

(3) Operation with a total flow within 10% of design flow.

c. In accordance with the Surveillance Frequency Control ProgramAt least once per 30 days on a STAGGERED TEST BASIS by operating each circuit for a minimum of 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />.
d. Anytime the HEPA filter bank or the charcoal absorbers have been partially or completely replaced, the test per 4.5.H.1.a(as applicable) will be performed prior to returning the system to OPERABLE STATUS.
e. Automatic initiation of each circuit in accordance with the Surveillance Frequency Control Programevery 18 months.

I. Inerting Surveillance When an inert atmosphere is required in the primary containment, the oxygen concentration in the primary containment shall be checked in accordance with the Surveillance Frequency Control Programat least weekly.

J. Drywell Coating Surveillance Carbon steel test panels coated with Firebar D shall be placed inside the drywell near the reactor core midplane level. They shall be removed for visual observation and weight loss measurements during the first, second, fourth and eighth refueling outages.

K. Instrument Line Flow Check Valves Surveillance The capability of a representative sample of instrument line flow check valves to isolate shall be tested in accordance with the Surveillance Frequency Control Programat least once per 24 months. In addition, each time an instrument line is returned to service after any condition which could have produced a pressure flow disturbance in that line, the open position of the flow check valve in that line shall be verified. Such conditions include:

OYSTER CREEK 4.5-5 Amendment No.: 132,186,216,219 Corrected by letter of 3/18/02

Leakage at instrument fittings and valves Venting an unisolated instrument or instrument line Flushing or draining an instrument Installation of a new instrument or instrument line L. Suppression Chamber Surveillance

1. In accordance with the Surveillance Frequency Control ProgramAt least once per day the suppression chamber water level and temperature and pressure suppression system pressure shall be checked.
2. A visual inspection of the suppression chamber interior, including water line regions, shall be made in accordance with the Surveillance Frequency Control Programat each major refueling outage.
3. Whenever heat from relief valve operation is being added to the suppression pool, the pool temperature shall be continually monitored and also observed until the heat addition is terminated.
4. Whenever operation of a relief valve is indicated and the suppression pool temperature reaches 160°F or above while the reactor primary coolant system pressure is greater than 180 psig, an external visual examination of the suppression chamber shall be made before resuming normal power operation.

M. Shock Suppressors (Snubbers)

As used in this specification, "type of snubber" shall mean snubbers of the same design and manufacturer, irrespective of capacity.

1. Each snubber shall be demonstrated OPERABLE by performance of the following inspection program:
a. Visual Inspections Snubbers are categorized as inaccessible or accessible during reactor operation. Each of the categories (inaccessible and accessible) may be inspected independently according to the schedule determined by Table 4.5-1. The visual inspection interval for each type of snubber shall be determined based upon the criteria provided in Table 4.5-1.

OYSTER CREEK 4.5-6 Amendment No.: 182, 186, 216

f. Snubber Service Life Monitoring A record of the service life of each snubber, the date at which the designated service life commences and the installation and maintenance records on which the designated service life is based shall be maintained as required by Specification 6.10.2.1.

Concurrent with the first inservice visual inspection and at least once per 24 months thereafter, the installation and maintenance records for each snubber shall be reviewed to verify that the indicated service life has not been exceeded or will not be exceeded prior to the next scheduled snubber service life review. If the indicated service life will be exceeded prior to the next scheduled snubber service life review, the snubber service life shall be re-evaluated or the snubber shall be replaced or reconditioned so as to extend its service life beyond the date of the next scheduled service life review. This re-evaluation, replacement or reconditioning shall be indicated in the records. Service life shall not at any time affect reactor operations.

N. Secondary Containment Isolation Valves

1. Each secondary containment isolation valve shall be demonstrated operable prior to returning the valve to service after maintenance, repair or replacement work is performed on the valve or its associated actuator by cycling the valve through at least one complete cycle of full travel. Following maintenance, repair or replacement work on the control or power circuit for the valves, the affected component shall be tested to assure it will perform its intended function in the circuit.
2. In accordance with the Surveillance Frequency Control ProgramAt least once per refueling outage, all valves shall be tested for automatic closure by an isolation signal.

OYSTER CREEK 4.5-9 Amendment No.: 168,186,219

A Primary Containment Leakage Rate Testing Program has been established to implement the requirements of 10 CFR 50, Appendix J, Option B, as modified by approved exemptions.

Guidance for implementation of Option B is contained in NRC Regulatory Guide 1.163, "Performance Based Containment Leak Test Program", Revision 0, dated September 1995.

Additional guidance for NRC Regulatory Guide 1.163 is contained in Nuclear Energy Institute (NEI) 94-01, "Industry Guideline for Implementing Performance Based Option of 10 CFR 50, Appendix J," Revision 0, dated July 26, 1995, and ANSI/ANS 56.8-1994, "Containment System Leakage Testing Requirements." The Primary Containment Leakage Rate Testing Program conforms with this guidance as modified by approved exemptions.

The maximum allowable leakage rate for the primary containment (La) is 1.0 percent by weight of the containment air per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at the design basis LOCA maximum peak containment pressure (Pa). As discussed below, Pa for the purpose of containment leak rate testing is 35 psig.

The penetration and air purge piping leakage test frequency, along with the containment leak rate tests, is adequate to allow detection of leakage trends. Whenever a double gasketed penetration (primary containment head equipment hatches and the absorption chamber access hatch) is broken and remade, the space between the gaskets is pressurized to determine that the seals are performing properly. The test pressure of 35 psig is consistent with the accident analyses and the maximum preoperational leak rate test pressure.

Monitoring the nitrogen makeup requirements of the inerting system provides a method of observing leak rate trends and would detect gross leaks in a very short time. This equipment must be periodically removed from service for test and maintenance, but this out-of-service time be kept to a practical minimum.

Automatic primary containment isolation valves are provided to maintain PRIMARY CONTAINMENT INTEGRITY following the design basis loss-of-coolant accident. Closure times for the automatic primary containment isolation valves are not critical because it is on the order of minutes before significant fission product release to the containment atmosphere for the design basis loss of coolant accident. These valves are highly reliable, see infrequent service and most of them are normally in the closed position. Therefore, a testing in accordance with the Surveillance Frequency Control Programduring each REFUELING OUTAGE is sufficient.

Large lines connecting to the reactor coolant system, whose failure could result in uncovering the reactor core, are supplied with automatic isolation valves (except containment cooling).

Closure times restrict coolant loss from the circumferential rupture of any of these lines outside primary containment to less than that for a main steam line break (the design basis accident for outside containment line breaks). The minimum time for main steam isolation valve (MSIV) closure of 3 seconds is based on the transient analysis that shows the pressure peak 76 psig below the lowest safety valve setting. The maximum time for MSIV closure of 10 seconds is based on the value assumed for the main steam line break dose calculations and restricts coolant loss to prevent uncovering the reactor core. Per the ASME Code, the full closure test of the MSIVs during COLD SHUTDOWNs will ensure OPERABILITY and provide assurance that the valves maintain the required closing time. The provision for a minimum of 92 days between the tests ensures that full closure testing is not too frequent. The MSIVs are partially stroked quarterly periodically as part of reactor protection system instrument surveillance testing.

OYSTER CREEK 4.5-11 Amendment No.: 132,186,196,219,221,250, 268

Surveillance of the suppression chamber-reactor building vacuum breaker consists of OPERABILITY checks and leakage tests (conducted as part of the containment leak-tightness tests). These vacuum breakers are normally in the closed position and open only during tests or an accident condition. As a result, a testing frequency of three months for OPERABILITY is considered justified for this equipment. Tests, inspections and calibrations are performed in accordance with the Surveillance Frequency Control Programduring the REFUELING OUTAGEs, this frequency being based on equipment quality, experience, and engineering judgement, and plant risk.

The 14 suppression chamber-drywell vacuum relief valves are designed to open to the full open position (the position that curtain area is equivalent to valve bore) with a force equivalent to a 0.5 psi differential acting on the suppression chamber face of the valve disk. This opening specification assures that the design limit of 2.0 psid between the drywell and external environment is not exceeded. In accordance with the Surveillance Frequency Control ProgramOnce each REFUELING OUTAGE, each valve is tested to assure that it will open in response to a force less than that specified. Also, it is inspected to assure that it closes freely and operates properly.

The containment design has been examined to establish the allowable bypass area between the drywell and suppression chamber as 10.5 in2 (expressed as vacuum breaker open area). This is equivalent to one vacuum breaker disk off its seat 0.371 inch; this length corresponds to an angular displacement of 1.25°. A conservative allowance of 0.10 inch has been selected as the maximum permissible valve opening. Valve closure within this limit may be determined by light indication from two independent position detection and indication systems. Either system provides a control room alarm for a non-seated valve.

At the end of each refueling cycle, a leak rate test shall be performed to verify that significant leakage flow paths do not exist between the drywell and suppression chamber. The drywell pressure will be increased by at least 1 psi with respect to the suppression chamber pressure. The pressure transient (if any) will be monitored with a sensitive pressure gauge. If the drywell pressure cannot be increased by 1 psi over the suppression chamber pressure it would be because a significant leakage path exists: in this event, the leakage source will be identified and eliminated before POWER OPERATION is resumed. If the drywell pressure can be increased by 1 psi over the suppression chamber, the rate of change of the suppression chamber pressure must not exceed a rate equivalent to the rate of air flow from the drywell to the suppression chamber through a 2-inch orifice. In the event the rate of change of pressure exceeds this value, then the source of leakage will be identified and eliminated before POWER OPERATION is resumed.

The drywell suppression chamber vacuum breakers are exercised in accordance with the Surveillance Frequency Control Programevery 3 months and immediately following termination of discharge of steam into the suppression chamber. This monitoring of valve operability is intended to assure that valve operability and position indication system performance does not degrade between refueling inspections. When a vacuum breaker valve is exercised through an opening-closing cycle, the position indicating lights are designed to function as follows:

Full Closed 2 Green - On (Closed to 0.10" open) 1 Red - Off Open 0.10 " 2 Green - Off (0.10" open to full open) 2 Red - On OYSTER CREEK 4.5-12 Amendment No. 128,186,196,210,211,219 Corrected by letters of 3/18/02 and 4/5/02

In accordance with the Surveillance Frequency Control ProgramDuring each refueling outage, four suppression chamber-drywell vacuum breakers will be inspected to assure components have not deteriorated. Since valve internals are designed for a 40-year lifetime, an inspection program which cycles through all valves in about 1/10th of the design lifetime is extremely conservative. The alarm systems for the vacuum breakers will be calibrated in accordance with the Surveillance Frequency Control Programduring each refueling outage.

This frequency is based on experience and engineering judgement.

Initiating reactor building isolation and operation of the standby gas treatment system to maintain a 1/4 inch of water vacuum, tests the operation of the reactor building isolation valves, leakage tightness of the reactor building and performance of the standby gas treatment system. Checking the initiating sensors and associated trip channels demonstrates the capability for automatic actuation. Performing the reactor building in leakage test prior to refueling demonstrates secondary containment capability prior to extensive fuel handling operations associated with the outage.

Verifying the efficiency and operation of charcoal filters in accordance with the Surveillance Frequency Control Programonce per 18 months gives sufficient confidence of standby gas treatment system performance capability. A charcoal filter efficiency of 99% for halogen removal is adequate.

The in-place testing of charcoal filters is performed using halogenated hydrocarbon refrigerant which is injected into the system upstream of the charcoal filters. Measurement of the refrigerant concentration upstream and downstream of the charcoal filters is made using a gas chromatograph. The ratio of the inlet and outlet concentrations gives an overall indication of the leak tightness of the system. Although this is basically a leak test, since the filters have charcoal of known efficiency and holding capacity for elemental iodine and/or methyl iodide, the test also gives an indication of the relative efficiency of the installed system. The test procedure is an adaptation of test procedures developed at the Savannah River Laboratory which were described in the Ninth AEC Cleaning Conference.*

High efficiency particulate filters are installed before and after the charcoal filters to minimize potential releases of particulates to the environment and to prevent clogging of the iodine filters.

An efficiency of 99% is adequate to retain particulates that may be released to the reactor building following an accident. This will be demonstrated by testing with DOP at testing medium.

The 95% methyl iodide removal efficiency is based on the formula in GL 99-02 for allowable penetration [(100% - 90% credited in DBA analysis) divided by a safety factor of 2]. If the allowable penetration is 5%, the required removal efficiency is 95%. If laboratory tests for the adsorber material in one circuit of the Standby Gas Treatment System are unacceptable, all adsorber material in that circuit shall be replaced with adsorbent qualified according to Regulatory Guide 1.52. Any HEPA filters found defective shall be replaced with those qualified with Regulatory Position C.3.d of Regulatory Guide 1.52.

  • D.R. Muhabier. "In Place Nondestructive Leak Test for Iodine Adsorbers." Proceedings of the Ninth AEC Air Cleaning Conference. USAEC Report CONF-660904, 1966 OYSTER CREEK 4.5-13 Amendment No.: 186, 195, 219

The snubber inspection frequency is based upon the number of unacceptable snubbers found during the previous inspection, the total population or category size for each snubber type, and the previous inspection interval. A snubber is considered unacceptable if it fails to satisfy the acceptance criteria of the visual inspection. Snubbers may be categorized, based upon their accessibility during power operation, as accessible or inaccessible. These categories may be examined separately or jointly. However, that decision must be made and documented before any inspection and used as the basis upon which to determine the next inspection interval for that category.

If continued operation cannot be justified with an unacceptable snubber, the snubber shall be declared inoperable and the applicable action requirements met. To determine the next surveillance interval, the snubber may be reclassified as acceptable if it can be demonstrated that the snubber is operable in its as-found condition by the performance of a functional test and if it satisfies the acceptance criteria for functional testing.

The next visual inspection interval may be twice, the same, or reduced by as much as two-thirds of the previous inspection interval. This interval depends on the number of unacceptable snubbers found in proportion to the size of the population or category for each type of snubber included in the previous inspection. Table 4.5-1 establishes the length of the next visual inspection interval.

To further increase the assurance of snubber reliability, functional tests should be performed once each refueling cycle. These tests will include stroking of the snubbers to verify proper piston movement, lock-up and bleed. Ten percent represents an adequate sample for such tests.

Observed failures of these samples require testing of additional units.

After the containment oxygen concentration has been reduced to meet the specification initially, the containment atmosphere is maintained above atmospheric pressure by the primary containment inerting system. This system supplies nitrogen makeup to the containment so that the very slight leakage from the containment is replaced by nitrogen, further reducing the oxygen concentration. In addition, the oxygen concentration is continuously recorded and high oxygen concentration is annunciated. Therefore, a weekly periodic check of oxygen concentration is adequate. This system also provides the capability for determining if there is gross leakage from the containment.

The drywell exterior was coated with Firebar D prior to concrete pouring during construction.

The Firebar D separated the drywell steel plate from the concrete. After installation, the drywell liner was heated and expanded to compress the Firebar D to supply a gap between the steel drywell and the concrete. The gap prevents contact of the drywell wall with the concrete which might cause excessive local stresses during drywell expansion in a loss-of-coolant accident.

The surveillance program is being conducted to demonstrate that the Firebar D will maintain its integrity and not deteriorate throughout plant life. The surveillance frequency is adequate to detect any deterioration tendency of the material.(8)

OYSTER CREEK 4.5-14 Amendment No.: 182,186,219

4.6 RADIOACTIVE EFFLUENT Applicability: Applies to monitoring of gaseous and liquid radioactive effluents of the Station during release of effluents via the monitored pathway(s). Each Surveillance Requirement applies whenever the corresponding Specification is applicable unless otherwise stated in an individual Surveillance Requirement. Surveillance Requirements do not have to be performed on inoperable equipment.

Objective: To measure radioactive effluents adequately to verify that radioactive effluents are as low as is reasonable achievable and within the limit of 10 CFR Part 20.

Specification:

A. Reactor Coolant Reactor coolant shall be sampled and analyzed in accordance with the Surveillance Frequency Control Programat least once every 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for DOSE EQUIVALENT I-131 during RUN MODE, STARTUP MODE and SHUTDOWN CONDITION.

B. NOT USED.

C. Radioactive Liquid Storage

1. Liquids contained in the following tanks shall be sampled and analyzed for radioactivity in accordance with the Surveillance Frequency Control Programat least once per 7 days when radioactive liquid is being added to the tank:
a. Waste Surge Tank, HP-T-3;
b. Condensate Storage Tank.

D. Main Condenser Offgas Treatment RELOCATED TO THE ODCM.

E. Main Condenser Offgas Radioactivity

1. The gross radioactivity in fission gases discharged from the main condenser air ejector shall be measured by sampling and analyzing the gases.
a. in accordance with the Surveillance Frequency Control Programat least once per month, and
b. When the reactor is operating at more than 40 percent of rated power, within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after an increase in the fission gas release via the air ejector of more than 50 percent, as indicated by the Condenser Air Ejector Offgas Radioactivity Monitor after factoring out increase(s) due to change(s) in the THERMAL POWER level.

F. Condenser Offgas Hydrogen Concentration The concentration of hydrogen in offgases downstream of the recombiner in the Offgas System shall be monitored with hydrogen instrumentation as described in Table 3.15.2.

G. NOT USED.

H. NOT USED.

OYSTER CREEK 4.6-1 Amendment No.: 108,126,166,191, 266

4.7 AUXILIARY ELECTRICAL POWER Applicability: Applies to surveillance requirements of the auxiliary electrical supply.

Objective: To verify the availability of the auxiliary electrical supply.

Specification:

A. Diesel Generator

1. Each diesel generator shall be started and loaded to not less than 80% rated load in accordance with the Surveillance Frequency Control Programevery two weeks.
2. The two diesel generators shall be automatically actuated and functionally tested in accordance with the Surveillance Frequency Control Programduring each refueling outage. This shall include testing of the diesel generator load sequence timers listed in Table 3.1.1.
3. Deleted.
4. The diesel generators' fuel supply shall be checked following the above tests.
5. The diesel generators' starting batteries shall be tested and monitored per Specification 4.7.B.

B. Diesel Generator Starting Batteries

1. Weekly Surveillance will be performed in accordance with the Surveillance Frequency Control Program to verify the following:
a. The active metallic surface of the plates shall be fully covered with electrolyte in all batteries.
b. The designated pilot cell voltage is greater than or equal to 2.0 volts.
c. The overall battery voltage is greater than or equal to 112 volts while the battery is on a float charge.
d. The pilot cell specific gravity, corrected to 77°F, is greater than or equal to 1.190.
2. Quarterly Surveillance will be performed in accordance with the Surveillance Frequency Control Program to verify the specific gravity for each fourth cell is greater than or equal to 1.190 when corrected to 77°F. The specific gravity and electrolyte temperature of every fourth cell shall be recorded for surveillance review.
3. Annual Surveillance will be performed in accordance with the Surveillance Frequency Control Program to verify the specific gravity for each cell is greater than or equal to 1.190 when corrected to 77°F. The electrolyte temperature and specific gravity for every cell shall be recorded for surveillance review.

OYSTER CREEK 4.7-1 Amendment No.: 144,189,197, 227, 236,245 Corrected by letter of 10/15/2004

4. In accordance with the Surveillance Frequency Control ProgramAt least once per 12 months, the diesel generator battery capacity shall be demonstrated to be able to supply the design duty loads (diesel start) during a battery service test.
5. In accordance with the Surveillance Frequency Control ProgramAt least once per 24 months, the following tests will be performed (perform during plant shutdowns or during 24-month Diesel Generator inspections):
a. Battery capacity shall be demonstrated to be at least 80% of the manufacturers' rating when subjected to a battery capacity discharge test.
b. If a Diesel Generator Starting Battery is demonstrated to have less than 85% of manufacturers ratings during a capacity discharge test, it shall be replaced within 2 years.

C. Station Batteries

1. Weekly Surveillance will be performed in accordance with the Surveillance Frequency Control Program to verify the following:
a. The overall battery voltage is greater than or equal to the minimum established float voltage.
b. Each station battery float current is 2 amps when battery terminal voltage is greater than or equal to the minimum established float voltage of 4.7.C.1.a.
2. Monthly Surveillance will be performed in accordance with the Surveillance Frequency Control Program to verify the following:
a. The electrolyte level in each station battery is greater than or equal to minimum established design limits.
b. The voltage of each pilot cell is greater than or equal to 2.07 volts while the respective battery is on a float charge.
c. The electrolyte temperature of each station battery pilot cell is greater than or equal to minimum established design limits.
3. Quarterly Surveillance will be performed in accordance with the Surveillance Frequency Control Program to verify the voltage of each connected cell is greater than or equal to 2.07 volts while the respective battery is on a float charge.

Oyster Creek 4.7-2 Amendment No. 142, 189, 197, 227, 245 Corrected by letter of 10/15/2004

4. In accordance with the Surveillance Frequency Control ProgramAt least once per 24 months:
a. The station battery capacity shall be demonstrated to be able to supply the design duty cycle loads during a battery service test. The modified performance discharge test may be substituted for the service test.
b. (i) Verify required station battery charger supplies 429 amps for the B MG Set charger, 600 amps for the A/B static charger, and 500 amps for the C charger, for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> at greater than or equal to the minimum established float voltage, or (ii) Verify each required battery charger can recharge the battery to the fully charged state while supplying the normal steady state DC loads during station operation, after a battery discharge to the bounding design basis event discharge state.
5. The following tests will be performed to verify battery capacity (perform during plant shutdowns for Station Batteries B and C):
a. In accordance with the Surveillance Frequency Control ProgramAt least once per 60 months, battery capacity shall be demonstrated to be at least 80% of the manufacturers' rating when subjected to a performance discharge test or a modified performance discharge test.
b. Performance discharge tests or modified performance discharge tests of station battery capacity shall be given at least once per 12 months when:

(i) The station battery shows degradation, or (ii) The station battery has reached 85% of expected life with battery capacity < 100% of manufacturers rating.

c. Performance discharge tests or modified performance discharge tests of station battery capacity shall be given at least once per 24 months when the battery has reached 85% of expected life with battery capacity 100% of manufacturers rating.

Oyster Creek 4.7-3 Amendment No. 245

Basis: The biweekly tests of the diesel generators are primarily to check for failures and deterioration in the system since last use. The manufacturer has recommended the two week test interval, based on experience with many of their engines. One factor in determining this test interval (besides checking whether or not the engine starts and runs) is that the lubricating oil should be circulated through the engine approximately every two weeks. The diesels should be loaded to at least 80% of rated load until engine and generator temperatures have stabilized (about one hour). The minimum 80% load will prevent soot formation in the cylinders and injection nozzles. Operation up to an equilibrium temperature ensures that there is no over-heat problem. The tests also provide an engine and generator operating history to be compared with subsequent engine-generator test data to identify and correct any mechanical or electrical deficiency before it can result in a system failure.

The test during refueling outages is more comprehensive tests, including procedures that are most effectively conducted at that time. These include automatic actuation and functional capability tests, to verify that the generators can start and assume load in less than 20 seconds and testing of the diesel generator load sequence timers which provide protection from a possible diesel generator overload during LOCA conditions.

The diesel generator batteries are challenged every two weeks to perform the 80% load test. This effectively performs an uninstrumented battery service test. The biweekly diesel start, when combined with the annual battery service test, provides an extensive amount of data on battery performance characteristics. This test data negates the need to lower the battery performance test interval from biennial to annually.

The diesel batteries shall be tested and monitored in accordance with the requirements of Specification 4.7.B to ensure their viability. The requirement to replace any battery in the next refueling outage or within 2 years which demonstrates less than 85% of manufacturers capacity during a capacity discharge test provides additional assurance of continued battery operability.

Verifying, per 4.7.C.1.a, battery terminal voltage while on float charge for the batteries helps to ensure the effectiveness of the battery chargers, which support the ability of the batteries to perform their intended function. Float charge is the condition in which the charger is supplying the continuous charge required to overcome the internal losses of a battery and maintain the battery in a fully charged state while supplying the continuous steady state loads of the associated DC subsystem. On float charge, battery cells will receive adequate current to optimally charge the battery. The voltage requirements are based on the minimum float voltage established by the battery manufacturer (2.17 V per cell average, or 130.2 V at the battery terminals). This voltage maintains the battery plates in a condition that supports maintaining the grid life (expected to be approximately 40 years for B station battery; 20 years for C station battery). The weekly frequency is consistent with manufacturer recommendations and IEEE Standard 450-1995The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk, and is controlled under the Surveillance Frequency Control Program.

OYSTER CREEK 4.7-4 AMENDMENT NO: 142,189,197,227, 236, 245 Corrected by letter of 10/15/2004

Verifying battery float current while on float charge (4.7.C.1.b) is used to determine the state of charge of the battery. Float charge is the condition in which the charger is supplying the continuous charge required to overcome the internal losses of a battery and maintain the battery in a charged state. The float current requirements are based on the float current indicative of a charged battery. Use of float current to determine the state of charge of the battery is consistent with IEEE Standard 450-1995. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk, and is controlled under the Surveillance Frequency Control ProgramThe weekly frequency is consistent with IEEE Standard 450-1995.

This Surveillance Requirement (4.7.C.1.b) provides that the float current requirement is not required to be met when battery terminal voltage is less than the minimum established float voltage of 4.7.C.1.a. When this float voltage is not maintained the Actions of 3.7.D.1 are being taken, which provide the necessary and appropriate verifications of the battery condition.

Furthermore, the float current limits are established based on the float voltage range and is not directly applicable when this voltage is not maintained.

The 4.7.C.2.a minimum established design limit for electrolyte level ensures that the plates suffer no physical damage and maintains adequate electron transfer capability. For the station batteries, this is the minimum level mark on the side of the battery cell. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk, and is controlled under the Surveillance Frequency Control ProgramThe Frequency is consistent with IEEE-450-1995.

Surveillance Requirements 4.7.C.2.b and 4.7.C.3 require verification that the cell float voltages are equal to or greater than 2.07 V. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk, and is controlled under the Surveillance Frequency Control ProgramThe frequencies for cell voltage verification (monthly for pilot cell, and quarterly for each connected cell) are consistent with IEEE Standard 450-1995.

Surveillance Requirement 4.7.C.2.c verifies that the pilot cell temperature is greater than or equal to the minimum established design limit (i.e., 60 degrees Fahrenheit for station battery B; 50 degrees Fahrenheit for station battery C). Cell electrolyte temperature is maintained above these temperatures to assure the battery can provide the required current and voltage to meet the design requirements. Temperatures lower than assumed in battery sizing calculations act to inhibit or reduce battery capacity. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk, and is controlled under the Surveillance Frequency Control ProgramThe Frequency is consistent with IEEE Standard 450-1995.

A battery service test, per 4.7.C.4.a, is a special test of the station battery capability, as found, to satisfy the design requirements (battery duty cycle) of the DC auxiliary electrical power system.

The discharge rate and test length corresponds to the design duty cycle requirements.

Surveillance Requirement 4.7.C.4.b verifies the design capacity of the station battery chargers.

The battery charger supply is based on normal steady state DC loads during station operation and the charging capacity to restore the battery from the design minimum charge state to the fully charged state. The minimum required amperes and duration ensures that these requirements can be satisfied. The battery is recharged when the measured charging current is 2 amps.

Surveillance Requirement 4.7.C.4.b(i) requires that each required station battery charger (i.e.,

only one charger per station battery required for compliance with 3.7.A.4) be capable of supplying the amps listed for the specified charger at the minimum established float voltage for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The ampere requirements are based on the output OYSTER CREEK 4.7-5 Amendment No. 245

4.8 ISOLATION CONDENSER Applicability: Applies to periodic testing requirements for the isolation condenser system.

Objective: To verify the operability of the isolation condenser system.

Specification: A. Surveillance of each isolation condenser loop shall be as follows:

Item Frequency

1. Operability of motor- Note 1Once/3 months operated isolation valves and condensate makeup valves.
2. Automatic actuation and Note 1Each refueling outage functional test. (interval not to exceed 20 months) or following major repair.
3. Shell side water volume Note 1Once/day check
4. Isolation valve (steam side)
a. Visual inspection Note 1Each refueling outage
b. External leakage check Each primary system Leak test
c. Area temperature check Note 1Once/shift Note 1: Surveillance Frequencies are specified in the Surveillance Frequency Control Program unless otherwise noted above.

Basis: Motor-operated valves on the isolation condenser steam and condensate lines and on the condensate makeup line that are normally on standby should be exercised periodically to make sure that they are free to operate. The valves will be stroked full length every time they are tested to verify proper functional performance. This frequency of testing is consistent with instrumentation tests discussed in Specification 4.1. Testing of these components per the ASME Code once every 3 monthsin accordance with the Surveillance Frequency Control Program provides assurance of availability of the system. Also, at this frequency of testing, wearout should not be a problem throughout the life of the plant.

The automatic actuation and functional test will demonstrate the automatic opening of the condensate return line valves and the automatic closing of the isolation valves on the vent lines to the main steam lines. Automatic closure of the isolation condenser steam and condensate lines on actuation of the condenser pipe break detectors will also be verified by the test. It is during a major maintenance or repair that a system's design intent may be violated accidentally. This makes the functional test necessary after every major repair operation.

By virtue of normal plant operation the operators daily observe the water level in the isolation condensers. In addition, isolation condenser shell side water level sensors provide control room annunciation of condenser high or low water level.

OYSTER CREEKI 4.8-1 Amendment No. 209, 268

In accordance with the Surveillance Frequency Control ProgramEach refueling outage the insulation will be periodically removed from the steam side isolation valve and the external valve bodies will be inspected for signs of deterioration.

Additionally, special attention is specified for these valves during primary system leakage tests and the temperature in the area of these valves is checked in accordance with the Surveillance Frequency Control Programonce each shift for temperature increases that would indicate valve leakage. The special attention (1) given these valves in the design and during their construction along with the indicated surveillance is judged to be adequate to assure that these valves will maintain their integrity when they are required for isolation of the primary containment.

Reference (1) Licensing Application, Amendment 32, Question 5 OYSTER CREEK 4.8-2

4.9 REFUELING Applicability: Applies to the periodic testing of those interlocks and instruments used during refueling.

Objective: To verify the operability of instrumentation and interlocks in use during refueling.

Specification: A. The refueling interlocks shall be tested prior to any fuel handling with the head off the reactor vessel, at weekly intervalsin accordance with the Surveillance Frequency Control Program thereafter until no longer required and following any repair work associated with the interlocks.

B. Prior to beginning any core alterations, the source range monitors (SRMs) shall be calibrated. Thereafter, the SRM's will be checked daily, tested monthly, and calibrated in accordance with the Surveillance Frequency Control Programevery 3 months until no longer required.

C. Within four (4) hours prior to the start of control rod removal pursuant to Specification 3.9.E verify:

1. That the reactor mode switch is locked in the refuel position and that the one rod out refueling interlock is operable.
2. That two (2) SRM channels, one in the core quadrant where the control rod is being removed and one in an adjacent quadrant, are operable and inserted to the normal operation level.

D. Verify within four (4) hours prior to the start of control rod removal pursuant to Specification 3.9.F and in accordance with the Surveillance Frequency Control Programat least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter, until replacement of all control rods or rod drive mechanisms and all control rods are fully inserted that:

1. the reactor mode switch is locked in the refuel position and the one rod out refueling interlock is operable.
2. Two (2) SRM channels, one in the core quadrant where a control rod is being removed and one in an adjacent quadrant, are operable and fully inserted.
3. All control rods not removed are fully inserted with the exception of one rod which may be partially withdrawn not more than two notches to perform refueling interlock surveillance.
4. The four fuel assemblies surrounding each control rod or rod drive mechanism being removed or maintained at the same time are removed from the core cell.

OYSTER CREEK 4.9-1 Amendment No.: 23,43

4.10 ECCS RELATED CORE LIMITS Applicability: Applies to the periodic measurement during power operation of core parameters related to ECCS performance.

Objective: To assure that the limits of Section 3.10 are not being violated.

Specification:

A. Average Planar LHGR.

The APLHGR for each type of fuel as a function of average planar exposure shall be checked daily in accordance with the Surveillance Frequency Control Program during reactor operation at greater than or equal to 25% rated thermal power.

B. Local LHGR.

The LHGR as a function of core height shall be checked in accordance with the Surveillance Frequency Control Programdaily during reactor operation at greater than or equal to 25% rated thermal power.

C. Minimum Critical Power Ratio (MCPR).

1. MCPR shall be checked in accordance with the Surveillance Frequency Control Programdaily during reactor operation at greater than or equal to 25% rated thermal power.
2. The MCPR operating limit shall be determined within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of completing scram time testing as required in Specification 4.2.C.

Bases:

The term daily in Technical Specification 4.10 shall be conservatively interpreted as once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (with normal grace allowance). This applies to Technical Specification 4.10 surveillance requirements only.

The LHGR shall be periodically checked daily in accordance with the Surveillance Frequency Control Program to determine whether fuel burnup or control rod movement has caused changes in power distribution. Since changes due to burnup are slow, and only a few control rods are moved daily, a daily periodic check of power distribution is adequate.

The minimum critical power ratio (MCPR) is unlikely to change significantly during steady state power operation so that 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is an acceptable frequency for surveillance. In the event of a single pump trip, 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />sthe surveillance interval specified in the Surveillance Frequency Control Program remains acceptable because the accompanying power reduction is much larger than the change in MAPLHGR limits for four loop operation at the corresponding lower steady state power level as compared to five loop operation. The 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> frequency specified in the Surveillance Frequency Control Program is also acceptable for the APRM status check since neutron monitoring system failures are infrequent and a downscale failure of an APRM initiates a control rod withdrawal block, thus precluding the possibility of a control rod withdrawal error.

OYSTER CREEK 4.10-1 Amendment No.: 75, 249 ECR OC 04-00575 Corrected by letter of 10/20/04

4.12 Alternate Shutdown Monitoring Instrumentation Applicability: Applies to the surveillance requirements of the alternate shutdown monitoring instrumentation.

Objective: To specify the minimum frequency and type of surveillance to be applied to the alternate shutdown monitoring instrumentation.

Specification:

Each of the alternate shutdown monitoring channels shown in Table 4.12-1 shall be demonstrated operable by performance of the CHANNEL CHECK and CHANNEL CALIBRATION operations at the frequencies specified in the Surveillance Frequency Control Program unless otherwise notedshown in Table 4.12-1.

Basis:

The operability of the alternate shutdown monitoring instrumentation ensures that sufficient capability is available to permit shutdown and maintenance of hot shutdown of the plant from locations outside of the control room. The type and frequency of surveillances required in Table 4.12-1 are consistent with or more conservative than the BWR Standard Technical Specificationsbased on operating experience, equipment reliability, and plant risk, and are controlled under the Surveillance Frequency Control Program.

OYSTER CREEK 4.12-1 Amendment No.: 161, 263

TABLE 4.12-1 ALTERNATE SHUTDOWN MONITORING INSTRUMENTATION CHANNEL CHANNEL Functional Limit CHECK (Note 1) CALIBRATION (Note 1)

Reactor Pressure M Q Reactor Water Level (fuel zone) n/a Q Condensate Storage Tank Level M R Service Water Pump Discharge Pressure M R Control Rod Drive System Flowmeter M R Shutdown Cooling System Flowmeter n/a R Isolation Condenser B Shell Water Level M R Reactor Building Closed Cooling Water Pump Discharge Pressure M R Note 1: Frequencies are specified in the Surveillance Frequency Control Program unless otherwise noted in the table.

M - Monthly Q - Quarterly R - Refueling Outage OYSTER CREEK 4.12-2 Amendment No.: 114, 161, 263

4.13 ACCIDENT MONITORING INSTRUMENTATION Applicability: Applies to surveillance requirements for the accident monitoring instrumentation.

Objective: To verify the operability of the accident monitoring instrumentation.

Specification: A. Safety & Relief Valve Position Indicators Each primary and safety valve position indicator (primary detector*), relief and safety valve position indicator (backup indications**), and relief valve position indicator (common header temperature element**)accident monitoring instrumentation channel shall be demonstrated operable by performance of the CHANNEL CHECK and CHANNEL CALIBRATION operations at the frequencies shown specified in the Surveillance Frequency Control Programin Table 4.13-1.

B. Wide Range Drywell Pressure Monitor Each wide range drywell pressure monitor (PT/PR 53 &

54)accident monitoring instrumentation channel shall be demonstrated operable by performance of the CHANNEL CHECK and CHANNEL CALIBRATION operations at the frequencies specified in the Surveillance Frequency Control Programshown in Table 4.13-1.

C. Wide Range Torus Water Level Monitor Each wide range torus water level monitor (LT/LR 37 & 38)accident monitoring instrumentation channel shall be demonstrated operable by performance of the CHANNEL CHECK and CHANNEL CALIBRATION operations at the frequencies specified in the Surveillance Frequency Control Programshown in Table 4.13-1.

D. DELETED E. Containment High- Range Radiation Monitor Each containment high range radiation monitoraccident monitoring instrumentation channel shall be demonstrated operable by performance of the CHANNEL CHECK and CHANNEL CALIBRATION*** operations at the frequencies specified in the Surveillance Frequency Control Programshown in Table 4.13-1.

F. High Range Radioactive Noble Gas Effluent Monitor Each high range radioactive noble gas effluent monitor (main stack and turbine building ventaccident monitoring instrumentation channel shall be demonstrated operable by performance of the CHANNEL CHECK and CHANNEL CALIBRATION operations at the frequencies specified in the Surveillance Frequency Control Programshown in Table 4.13-1.

  • Acoustic Monitor
    • Thermocouple
      • CHANNEL CALIBRATION for the containment high range radiation monitor shall consist of electronic signal substitution of the channel, not including the detector, for all decades above 10R/hr and a one point calibration check of the detector at or below 10R/hr by means of a calibrated portable radiation source traceable to NBS.

OYSTER CREEK 4.13-1 Amendment No.: 54, 94, 116, 137, 246, 263

Bases:

The operability of the accident monitoring instrumentation ensures that sufficient information is available on selected plant parameters to monitor and assess these variables during and following an accident. This capability is consistent with NUREGs 0578 and 0737.

OYSTER CREEK 4.13-1a Amendment No.:

TABLE 4.13-1 ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL CHANNEL INSTRUMENT CHECK CALIBRATION

1. Primary and Safety Valve Position A B Indicator (Primary Detector*)

Relief and Safety Valve Position A B Indicator (Backup Indications**)

Relief Valve Position Indicator C B (Common Header Temperature Element**)

2. Wide Range Drywell Pressure Monitor A D (PT/PR 53 & 54)
3. Wide Range Torus Water Level Monitor A D (LT/LR 37 & 38)
4. DELETED
5. Containment High Range Radiation Monitor A F***
6. High Range Radioactive Noble Gas Effluent Monitor
a. Main Stack A G
b. Turbine Building Vent A G Legend:

A = at least once per 31 days B = at least once per 24 months C = at least once per 15 days until channel calibration is performed and thence at least once per 31 days D = at least once per 6 months E = DELETED F = each refueling outage G = once per 20 months INFORMATION ON THIS PAGE HAS BEEN DELETED

  • Acoustic Monitor
    • Thermocouple
      • CHANNEL CALIBRATION shall consist of electronic signal substitution of the channel, not including the detector, for all decades above 10R/hr and a one point calibration check of the detector at or below 10R/hr by means of a calibrated portable radiation source traceable to NBS.

OYSTER CREEK 4.13-2 Amendment No.: 54, 88, 94, 116, 127, 144, 146, 246, 263 Corrected letter of 2/14/91

4.15 Explosive Gas Monitoring Instrumentation Applicability: States surveillance requirements for OPERABILITY of explosive gas monitoring instrumentation.

Objective: To demonstrate the OPERABILITY of explosive gas monitoring instrumentation.

Specification:

Gaseous Effluent Instrumentation Each explosive gas effluent monitoring instrument channel shall be demonstrated OPERABLE by performance of the CHANNEL CHECK, CHANNEL CALIBRATION, and CHANNEL FUNCTIONAL TEST at the frequencies shown specified in the Surveillance Frequency Control Program unless otherwise noted in Table 4.15.2.

OYSTER CREEK 4.15-1 Amendment No.: 108, 166

TABLE 4.15.2 EXPLOSIVE GAS MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL CHANNEL CHANNEL SOURCE CHANNEL FUNCTIONAL SURVEILLANCE INSTRUMENT CHECK (h) CHECK CALIBRATION(f)(h) TEST (h) REQUIRED (a)

1. Main Condenser D N/A Q(g) M (c)

Offgas Treatment System Hydrogen Monitor Legend: D = once per 24 hrs; M = once per 31 days; Q = once per 92 days; N/A = Not Applicable.

TABLE 4.15.2 NOTATIONS (a) Instrumentation shall be OPERABLE and in service except that a channel may be taken out of services for the purpose of a check, calibration, test or maintenance without declaring it to be inoperable.

(c) During main condenser offgas treatment system operation.

(f) The CHANNEL CALIBRATION shall be performed according to established station calibration procedures.

(g) A CHANNEL CALIBRATION shall include the use of at least two standard gas samples, each containing a known volume percent hydrogen in the range of the instrument, balance nitrogen.

(h) Frequencies are specified in the Surveillance Frequency Control Program unless otherwise noted in the table.

OYSTER CREEK 4.15-2 Amendment No.: 137, 145, 155, 166, 263

4.17 Control Room Heating, Ventilating, and Air-Conditioning System Applicability: Applies to surveillance requirements for the control room heating, ventilating, and air conditioning (HVAC) systems.

Objective: To verify the capability of each control room HVAC system to minimize the amount of radioactivity from entering the control room in the event of an accident.

Specification: Surveillance of each control room HVAC system shall be as follows:

A. At least once monthlyIn accordance with the Surveillance Frequency Control Program: by initiating, from the control room, the partial recirculation mode of operation, and by verifying that the system components are aligned such that the system is operating in this mode.

B. At least once every refueling outageIn accordance with the Surveillance Frequency Control Program: by verifying that in the partial recirculation mode of operation, the control room and lower cable spreading room are maintained at a positive pressure of 1/8 in. WG relative to the outside atmosphere.

Basis: Periodic surveillance of each control room HVAC system is required to ensure the operability of the system. The operability of the system in conjunction with control room design provisions is based upon limiting the radiation exposure to personnel occupying the control room to less than a 30-day integrated dose of 5 rem TEDE for the most limiting design basis accident.

OYSTER CREEK 4.17-1 Amendment No.: 115, 139, 262

6.24 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 Definition 1.24 and Surveillance Requirement 4.0.2 are applicable to the Frequencies established in the Surveillance Frequency Control Program.

OYSTER CREEK 6-23 Amendment No.

ATTACHMENT 4 License Amendment Request Oyster Creek Nuclear generating Station Docket No. 50-219 Application for Technical Specification Change Regarding Risk-Informed Justification for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program (Adoption of TSTF-425, Revision 3)

TSTF-425 (NUREG-1433) vs. OCNGS Cross-Reference

LAR - Adoption of TSTF-425, Revision 3 Attachment 4 Docket No. 50-219 Page 1 of 10 TSTF-425 (NUREG-1433) vs. OCNGS Cross-Reference Technical Specification Section Title/Surveillance Description* TSTF-425 OCNGS Control Rod Operability 3.1.3 ---------------

Control rod position 3.1.3.1 ---------------

Notch test - fully withdrawn control rod one notch 3.1.3.2 4.2.D Notch test - partially withdrawn control rod one notch 3.1.3.3 4.2.D Control Rod Scram Times 3.1.4 ---------------

Scram time testing 3.1.4.2 4.2.C.3 Control Rod Scram Accumulators 3.1.5 ---------------

Control rod scram accumulator pressure 3.1.5.1 ---------------

Rod Pattern Control 3.1.6 ---------------

[BPWS] Analyzed rod position sequence 3.1.6.1 ---------------

Standby Liquid Control (SLC) System 3.1.7 4.2.E Volume of sodium pentaborate 3.1.7.1 4.2.E.4 Temperature of sodium pentaborate solution 3.1.7.2 4.2.E.4 Temperature of pump suction piping 3.1.7.3 ---------------

Continuity of explosive charge 3.1.7.4 ---------------

Concentration of boron solution 3.1.7.5 4.2.E.2 Manual/power operated valve position 3.1.7.6 ---------------

Pump flow rate 3.1.7.7 4.2.E.1 Flow through one SLC subsystem 3.1.7.8 4.2.E.3 Heat traced piping is unblocked 3.1.7.9 ---------------

Verify sodium pentaborate enrichment [Solution Boron-10 3.1.7.10 4.2.E.5 Enrichment] (NUREG-1433 - prior to addition to SLC tank)

Scram Discharge Volume (SDV) Vent & Drain Valves 3.1.8 4.2.G/4.2.H Each SDV vent & drain valve open 3.1.8.1 4.2.G Cycle each SDV vent & drain valve fully closed/fully open position 3.1.8.2 4.2.G Each SDV vent & drain valve closes on receipt of scram 3.1.8.3 4.2.H Average Planar Linear Heat Generation Rate (APLHGR) 3.2.1 4.10.A APLHGR less than or equal to limits 3.2.1.1 4.10.A Minimum Critical Power Ratio (MCPR) 3.2.2 4.10.C MCPR greater than or equal to limits 3.2.2.1 4.10.C.1 Linear Heat Generation Rate (LHGR) 3.2.3 4.10.B LHGR less than or equal to limits 3.2.3.1 4.10.B Average Power Range Monitor (APRM) Gain & Setpoints 3.2.4 ---------------

MFLPD is within limits 3.2.4.1 ---------------

APRM setpoints or gain are adjusted for calculated MFLPD 3.2.4.2 ---------------

Reactor Protection System (RPS) Instrumentation 3.3.1.1 4.1/

Table 4.1.2 Channel Check 3.3.1.1.1 Table 4.1.1 Absolute diff. between APRM channels & calculated power 3.3.1.1.2 ---------------

Adjust channel to conform to calibrated flow (APRM STP - Hi) 3.3.1.1.3 ---------------

Channel Functional Test (12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after entering Mode 2) 3.3.1.1.4 ---------------

Channel Functional Test (weekly/monthly) 3.3.1.1.5 ---------------

Calibrate local power range monitors 3.3.1.1.6 ---------------

Channel Functional Test (quarterly) 3.3.1.1.7 Table 4.1.1

LAR - Adoption of TSTF-425, Revision 3 Attachment 4 Docket No. 50-219 Page 2 of 10 Technical Specification Section Title/Surveillance Description* TSTF-425 OCNGS Calibrate trip units (quarterly) 3.3.1.1.8 ---------------

Channel Calibration (APRMs) 3.3.1.1.9 ---------------

Channel Functional Test (Reactor Mode Switch ) 3.3.1.1.10 ---------------

Channel Calibration 3.3.1.1.11 Table 4.1.1 Verify APRM Flow Biased STP - High 3.3.1.1.12 ---------------

Logic System Functional Test 3.3.1.1.13 ---------------

Verify TSV/TCV closure/Trip Oil Press-Low Not Bypassed 3.3.1.1.14 ---------------

Verify RPS Response Time 3.3.1.1.15 ---------------

Source Range Monitor (SRM) 3.3.1.2 4.1 Channel Check 3.3.1.2.1 Table 4.1.1 Verify Operable SRM Detector 3.3.1.2.2 4.9.D.2 Channel Check 3.3.1.2.3 ---------------

Verify count rate 3.3.1.2.4 ---------------

Channel Functional Test (7 days) 3.3.1.2.5 Table 4.1.1 Channel Functional Test (31 days) 3.3.1.2.6 ---------------

Channel Calibration 3.3.1.2.7 Table 4.1.1 Control Rod Block Instrumentation 3.3.2.1 4.1/

Table 4.1.2 Channel Functional Test (routine) 3.3.2.1.1 Table 4.1.1 Channel Functional Test (rod withdrawal at < 10% RTP) 3.3.2.1.2 ---------------

Channel Functional Test (thermal power < 10%) 3.3.2.1.3 ---------------

Verify RBM 3.3.2.1.4 ---------------

Verify RWM not bypassed 3.3.2.1.5 ---------------

Channel Functional Test 3.3.2.1.6 ---------------

Channel Calibration 3.3.2.1.7 Table 4.1.1 Feedwater & Main Turbine High Water Level Trip Instrumentation 3.3.2.2 ---------------

Channel Check 3.3.2.2.1 ---------------

Channel Functional Test 3.3.2.2.2 ---------------

Channel Calibration 3.3.2.2.3 ---------------

Logic System Functional Test 3.3.2.2.4 ---------------

Post Accident Monitor (PAM) Instrumentation 3.3.3.1 4.13 Channel Check 3.3.3.1.1 4.13/

Table 4.13-1 Calibration 3.3.3.1.2 4.13/

Table 4.13-1 Remote Shutdown System [Alternate Shutdown Monitoring] 3.3.3.2 4.12 Channel Check 3.3.3.2.1 Table 4.12-1 Verify control circuit and transfer switch capable of function 3.3.3.2.2 ---------------

Channel Calibration 3.3.3.2.3 Table 4.12-1 End-of-Cycle-Recirculation Pump Trip (RPT) Instrumentation 3.3.4.1 ---------------

Channel Functional Test 3.3.4.1.1 ---------------

Calibrate trip units 3.3.4.1.2 ---------------

Channel Calibration 3.3.4.1.3 ---------------

Logic System Functional Test 3.3.4.1.4 ---------------

Verify TSV/TCV Closure/Trip Oil Press-Low Not Bypassed 3.3.4.1.5 ---------------

Verify EOC-RPT System Response Time 3.3.4.1.6 ---------------

LAR - Adoption of TSTF-425, Revision 3 Attachment 4 Docket No. 50-219 Page 3 of 10 Technical Specification Section Title/Surveillance Description* TSTF-425 OCNGS Determine RPT breaker interruption time 3.3.4.1.7 ---------------

Anticipated Trip Without Scram-RPT Instrumentation 3.3.4.2 ---------------

Channel Check 3.3.4.2.1 ---------------

Channel Functional Test 3.3.4.2.2 ---------------

Calibrate trip units 3.3.4.2.3 ---------------

Channel Calibration 3.3.4.2.4 ---------------

Logic System Functional Test 3.3.4.2.5 ---------------

Emergency Core Cooling System (ECCS) Instrumentation 3.3.5.1 4.1/4.4.A/

Table 4.1.2 Channel Check 3.3.5.1.1 4.4.A.5/

Table 4.1.1 Channel Functional Test 3.3.5.1.2 4.4.A.5/

Table 4.1.1 Calibrate trip units 3.3.5.1.3 ---------------

Channel Calibration (HPCI: Condensate Storage Tank Level - Low) 3.3.5.1.4 ---------------

Channel Calibration 3.3.5.1.5 4.4.A.5/

Table 4.1.1 Logic System Functional Test 3.3.5.1.6 ---------------

Verify ECCS Response Time 3.3.5.1.7 ---------------

Reactor Core Isolation Cooling (RCIC) System Instrumentation 3.3.5.2 4.1/

[Isolation Condenser Instrumentation] Table 4.1.2 Channel Check 3.3.5.2.1 ---------------

Channel Functional Test 3.3.5.2.2 ---------------

Calibrate trip units 3.3.5.2.3 ---------------

Channel Calibration (Condensate Storage Tank Level - Low) 3.3.5.2.4 ---------------

Channel Calibration 3.3.5.2.5 Table 4.1.2 Logic System Functional Test 3.3.5.2.6 ---------------

Primary Containment Isolation Instrumentation 3.3.6.1 4.1/

Table 4.1.2 Channel Check 3.3.6.1.1 Table 4.1.1 Channel Functional Test 3.3.6.1.2 Table 4.1.1 Calibrate trip units 3.3.6.1.3 ---------------

Channel Calibration 3.3.6.1.4 ---------------

Channel Functional Test (HPCI/RCIC Suppr. Pool Area Temp.) 3.3.6.1.5 ---------------

Channel Calibration 3.3.6.1.6 Table 4.1.1 Logic System Functional Test 3.3.6.1.7 ---------------

Verify Isolation Response Time 3.3.6.1.8 ---------------

Secondary Containment Isolation Instrumentation 3.3.6.2 4.1/

Table 4.1.2 Channel Check 3.3.6.2.1 Table 4.1.1 Channel Functional Test 3.3.6.2.2 Table 4.1.1 Calibrate trip units 3.3.6.2.3 ---------------

Channel Calibration (Refueling Floor Exhaust Rad. - High) 3.3.6.2.4 ---------------

Channel Calibration 3.3.6.2.5 Table 4.1.1 Logic System Functional Test 3.3.6.2.6 ---------------

Verify Isolation Response Time 3.3.6.2.7 ---------------

LAR - Adoption of TSTF-425, Revision 3 Attachment 4 Docket No. 50-219 Page 4 of 10 Technical Specification Section Title/Surveillance Description* TSTF-425 OCNGS Low-Low-Set (LLS) Instrumentation 3.3.6.3 ---------------

Channel Check 3.3.6.3.1 ---------------

Channel Functional Test 3.3.6.3.2 ---------------

Channel Functional Test 3.3.6.3.3 ---------------

Channel Functional Test 3.3.6.3.4 ---------------

Calibrate trip units 3.3.6.3.5 ---------------

Channel Calibration 3.3.6.3.6 ---------------

Logic System Functional Test 3.3.6.3.7 ---------------

Main Control Room Environmental Control (MCREC) 3.3.7.1 ---------------

Channel Check 3.3.7.1.1 ---------------

Channel Functional Test 3.3.7.1.2 ---------------

Calibrate trip units 3.3.7.1.3 ---------------

Channel Calibration 3.3.7.1.4 ---------------

Logic System Functional Test 3.3.7.1.5 ---------------

Loss of Power (LOP) Instrumentation 3.3.8.1 4.1 Channel Check 3.3.8.1.1 Table 4.1.1 Channel Functional Test 3.3.8.1.2 Table 4.1.1 Channel Calibration 3.3.8.1.3 Table 4.1.1 Logic System Functional Test 3.3.8.1.4 ---------------

RPS Electric Power Monitoring 3.3.8.2 ---------------

Channel Functional Test 3.3.8.2.1 ---------------

Channel Calibration (RPS MG set/alt. power supply monitoring) 3.3.8.2.2 ---------------

System functional test 3.3.8.2.3 ---------------

Explosive Gas Monitoring Instrumentation ----------- 4.15 Channel Check, Channel Functional Test, Channel Calibration ----------- Table 4.15.2 Recirculation Loops Operating 3.4.1 ---------------

Recirc loop jet pump flow mismatch with both loops operating 3.4.1.1 ---------------

Jet Pumps 3.4.2 ---------------

Criteria satisfied for each operating recirc loop 3.4.2.1 ---------------

Safety/Relief Valves (SRVs) 3.4.3 ---------------

Safety function lift setpoints 3.4.3.1 ---------------

SRV opens when manually actuated 3.4.3.2 ---------------

Reactor Coolant System (RCS) Operational Leakage 3.4.4 4.3.H RCS unidentified and total leakage increase within limits 3.4.4.1 4.3.H.1 4.3.H.2 RCS Pressure Isolation Valve (PIV) Leakage 3.4.5 ---------------

Equivalent leakage of each PIV 3.4.5.1 ---------------

RCS Leakage Detection Instrumentation 3.4.6 ---------------

Channel Check 3.4.6.1 ---------------

Channel Functional Test 3.4.6.2 ---------------

Channel Calibration 3.4.6.3 4.3.H.3 RCS Specific Activity 3.4.7 4.6.A Dose Equivalent I-131 specific activity 3.4.7.1 4.6.A RCS Chemistry ------------ 4.3.F Chloride ion content and conductivity ------------ 4.3.F

LAR - Adoption of TSTF-425, Revision 3 Attachment 4 Docket No. 50-219 Page 5 of 10 Technical Specification Section Title/Surveillance Description* TSTF-425 OCNGS Residual Heat Removal (RHR) Shutdown Cooling - Hot Shutdown 3.4.8 ---------------

One RHR Shutdown cooling subsystem operating 3.4.8.1 ---------------

RHR Shutdown Cooling - Cold Shutdown 3.4.9 ---------------

One RHR Shutdown cooling subsystem operating 3.4.9.1 ---------------

RCS Pressure/Temperature Limit 3.4.10 ---------------

RCS pressure, temperature, heatup and cooldown rates 3.4.10.1 ---------------

RPV flange/head flange temperatures (tensioning head bolt stud) 3.4.10.7 ---------------

RPV flange/head flange temperatures (after RCS temp < 80oF) 3.4.10.8 ---------------

RPV flange/head flange temperatures (after RCS temp < 100oF) 3.4.10.9 ---------------

Reactor Steam Dome Pressure 3.4.11 ---------------

Verify reactor steam dome pressure 3.4.11.1 ---------------

ECCS - Operating 3.5.1 4.4 Verify injection/spray piping filled with water 3.5.1.1 ---------------

Verify each valve in flow path is in correct position 3.5.1.2 ---------------

Verify ADS nitrogen pressure 3.5.1.3 ---------------

Verify RHR (LPCI) cross tie valve is closed and power removed 3.5.1.4 ---------------

Verify LPCI inverter output voltage 3.5.1.5 ---------------

Verify ECCS pumps develop specified flow 3.5.1.7 4.4.A.1

[Core Spray Pump, Containment Cooling System Pump, 4.4.C.1 Emergency Service Water System Pump, Control Rod Drive 4.4.D.1 Hydraulic System Pump, Fire Protection System Pump] 4.4.E.1 4.4.F.1 Verify HPCI flow rate (Rx press < [1020], > [920]) 3.5.1.8 ---------------

Verify HPCI flow rate (Rx press < [165]) 3.5.1.9 ---------------

Verify ECCS actuates on initiation signal 3.5.1.10 4.4.A.3 Verify ADS actuates on initiation signal 3.5.1.11 4.4.B.2 Verify each ADS valve opens [actuator strokes] when manually 3.5.1.12 4.4.B.1 actuated Verify motor-operated valve operability ----------- 4.4.A.2

[Core Spray System, Containment Cooling System, Fire Protection 4.4.C.2 System] 4.4.F.2 Verify pump compartment water-tight doors closed ------------ 4.4.A.4

[Core Spray System, Containment Cooling System] 4.4.C.3 ECCS - Shutdown 3.5.2 ---------------

Verify, for LPCI, suppression pool water level 3.5.2.1 ---------------

Verify, for CS, suppression pool water level and CST water level 3.5.2.2 ---------------

Verify ECCS piping filled with water 3.5.2.3 ---------------

Verify each valve in flow path is in correct position 3.5.2.4 ---------------

Verify each ECCS pump develops flow 3.5.2.5 ---------------

Verify ECCS actuates on initiation signal 3.5.2.6 ---------------

RCIC System [Isolation Condenser] 3.5.3 4.8.A Verify RCIC piping filled with water 3.5.3.1 ---------------

Verify each valve in flow path is in correct position 3.5.3.2 ---------------

Verify RCIC flow rate (Rx press < [1020], > [920]) 3.5.3.3 ---------------

Verify RCIC flow rate (Rx press < [165]) 3.5.3.4 ---------------

Verify RCIC actuates on initiation signal 3.5.3.5 ---------------

LAR - Adoption of TSTF-425, Revision 3 Attachment 4 Docket No. 50-219 Page 6 of 10 Technical Specification Section Title/Surveillance Description* TSTF-425 OCNGS Operability of motor-operated isolation valves and condensate ----------- 4.8.A.1 makeup valves Automatic actuation and functional test ----------- 4.8.A.2 Shell side water volume check ----------- 4.8.A.3 Isolation valve (steam side) visual inspection, external leakage ----------- 4.8.A.4 check, and area temperature check.

Primary Containment 3.6.1.1 4.5 Verify drywell to suppression chamber differential pressure 3.6.1.1.2 4.5.F.5.b(4)

Primary Containment Air Lock 3.6.1.2 ---------------

Verify only one door can be opened at a time 3.6.1.2.2 ---------------

Primary Containment Isolation Valves (PCIVs) 3.6.1.3 4.5.F Verify purge valve is closed except one valve in a penetration 3.6.1.3.1 ---------------

Verify each 18 inch (6 inch & 18 inch) PC purge valve is closed 3.6.1.3.2 ---------------

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

Verify isolation time of each power operated PCIV 3.6.1.3.6 4.5.F.1 Perform leakage rate testing on each PC purge valve 3.6.1.3.7 ---------------

Verify isolation time of MSIVs (OCNGS 4.5.F.3 - no change) 3.6.1.3.8 4.5.F.1 Verify automatic PCIV actuates to isolation position 3.6.1.3.9 4.5.F.1 Verify sample of Excess Flow Check Valves actuate to isolation 3.6.1.3.10 4.5.K position Test explosive squib from each shear valve 3.6.1.3.11 ---------------

Verify each purge valve is blocked 3.6.1.3.15 ---------------

Drywell Pressure 3.6.1.4 ---------------

Verify drywell pressure is within limit 3.6.1.4.1 ---------------

Drywell Average Air Temperature 3.6.1.5 ---------------

Verify drywell average air temperature is within limit 3.6.1.5.1 ---------------

LLS Valves 3.6.1.6 ---------------

Verify each LLS valve opens when manually actuated 3.6.1.6.1 ---------------

Verify LLS system actuates on initiation signal 3.6.1.6.2 ---------------

Reactor Building - Suppression Chamber Vacuum Breakers 3.6.1.7 4.5.F.4 Verify each vacuum breaker is closed 3.6.1.7.1 ---------------

Perform functional test on each vacuum breaker 3.6.1.7.2 4.5.F.4.a Verify opening setpoint for each vacuum breaker 3.6.1.7.3 4.5.F.4.a 4.5.F.4.b Air-operated vacuum breaker instrumentation calibration ----------- 4.5.F.4.b Suppression Chamber - Drywell Vacuum Breakers 3.6.1.8 4.5.F.5 Verify each vacuum breaker is closed 3.6.1.8.1 ---------------

Perform functional test on each vacuum breaker 3.6.1.8.2 4.5.F.5.a Verify opening setpoint for each vacuum breaker 3.6.1.8.3 4.5.F.5.b(1)

Vacuum breaker position indication and alarm calibration ----------- 4.5.F.5.b(2)

Vacuum breaker inspection ----------- 4.5.F.5.b(3)

Main Steam Isolation Valve (MSIV) Leakage Control System 3.6.1.9 ---------------

Operate each MSIV LCS blower 3.6.1.9.1 ---------------

Verify continuity of inboard MSIV LCS heater element 3.6.1.9.2 ---------------

Perform functional test of each MSIV LCS subsystem 3.6.1.9.3 ---------------

Suppression Pool Average Temperature 3.6.2.1 4.5.L

LAR - Adoption of TSTF-425, Revision 3 Attachment 4 Docket No. 50-219 Page 7 of 10 Technical Specification Section Title/Surveillance Description* TSTF-425 OCNGS Verify suppression pool average temperature within limits 3.6.2.1.1 4.5.L.1 Suppression Pool Water Level 3.6.2.2 4.5.L Verify suppression pool water level within limits 3.6.2.2.1 4.5.L.1 Suppression Chamber ----------- 4.5.L Suppression chamber visual inspection ----------- 4.5.L.2 RHR Suppression Pool Cooling 3.6.2.3 ---------------

Verify each valve in flow path is in correct position 3.6.2.3.1 ---------------

Verify each RHR pump develops flow rate 3.6.2.3.2 ---------------

RHR Suppression Pool Spray 3.6.2.4 ---------------

Verify each valve in flow path is in correct position 3.6.2.4.1 ---------------

Verify RHR pump develops flow rate 3.6.2.4.2 ---------------

Drywell - Suppression Chamber Differential Pressure 3.6.2.5 ---------------

Verify differential pressure is within limit 3.6.2.5.1 ---------------

Drywell Cooling System Fans 3.6.3.1 ---------------

Operate each fan > 15 minutes 3.6.3.1.1 ---------------

Verify each fan flow rate 3.6.3.1.2 ---------------

Primary Containment Oxygen Concentration 3.6.3.2 4.5.I Verify PC oxygen concentration is within limits 3.6.3.2.1 4.5.I Containment Atmosphere Dilution (CAD) System 3.6.3.3 ---------------

Verify CAD liquid nitrogen storage 3.6.3.3.1 ---------------

Verify each CAD valve in flow path is in correct position 3.6.3.3.2 ---------------

Secondary Containment 3.6.4.1 4.5.G Verify SC vacuum is > 0.25 inch of vacuum water gauge 3.6.4.1.1 4.5.G.2 Verify all SC equipment hatches closed and sealed 3.6.4.1.2 ---------------

Verify one SC access door in each opening is closed 3.6.4.1.3 ---------------

Verify SC drawn down using one SGTS 3.6.4.1.4 ---------------

Verify SC can be maintained using one SGTS 3.6.4.1.5 ---------------

Secondary Containment Isolation Valves 3.6.4.2 4.5.N Verify each SC isolation manual valve is closed 3.6.4.2.1 ---------------

Verify isolation time of each SCIV 3.6.4.2.2 ---------------

Verify each automatic SCIV actuates to isolation position 3.6.4.2.3 4.5.N.2 Standby Gas Treatment (SGT) System 3.6.4.3 4.5.H Operate each SGT subsystem for 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> 3.6.4.3.1 4.5.H.1.c SGT filter testing [NUREG-1433 - Ventilation Filter Testing 3.6.4.3.2 4.5.H.1.b Program]

Verify each SGT subsystem actuates on initiation signal 3.6.4.3.3 4.5.H.1.a 4.5.H.1.e Verify each SGT filter cooler bypass damper can be opened 3.6.4.3.4 ---------------

Residual Heat Removal Service Water (RHRSW) System 3.7.1 ---------------

Verify each RHRSW valve in flow path in correct position 3.7.1.1 ---------------

Plant Service Water (PSW) System and Ultimate Heat Sink (UHS)/ 3.7.2/ ---------------

Diesel Generator (DG) Standby Service Water (SSW) System 3.7.3 Verify water level in cooling tower basin 3.7.2.1 ---------------

Verify water level in pump well of pump structure 3.7.2.2 ---------------

Verify average water temperature of heat sink 3.7.2.3 ---------------

Operate each cooling tower fan 3.7.2.4 ---------------

LAR - Adoption of TSTF-425, Revision 3 Attachment 4 Docket No. 50-219 Page 8 of 10 Technical Specification Section Title/Surveillance Description* TSTF-425 OCNGS Verify each PSW/DG SSW valve in flow path is in correct position 3.7.2.5/ ---------------

3.7.3.1 Verify PSW/DG SSW actuates on initiation signal 3.7.2.6/ ---------------

3.7.3.2 MCREC [Control Room HVAC] System 3.7.4 4.17 Operate each MCREC [Control Room HVAC] subsystem 3.7.4.1 4.17.A Verify each subsystem actuates on initiation signal 3.7.4.3 ---------------

Verify each subsystem can maintain positive pressure 3.7.4.4 4.17.B Control Room Air Conditioning System 3.7.5 ---------------

Verify each subsystem has capability to remove heat load 3.7.5.1 ---------------

Main Condenser Offgas 3.7.6 4.6.E Verify gross gamma activity rate of the noble gases 3.7.6.1 4.6.E.1.a Main Turbine Bypass System 3.7.7 ---------------

Verify one complete cycle of each main turbine bypass valve 3.7.7.1 ---------------

Perform system functional test 3.7.7.2 ---------------

Verify Turbine Bypass System Response Time within limits 3.7.7.3 ---------------

Spent Fuel Storage Pool Water Level 3.7.8 ---------------

Verify spent fuel storage pool water level 3.7.8.1 ---------------

AC Sources - Operating 3.8.1 4.7.A Verify correct breaker alignment 3.8.1.1 ---------------

Verify each DG starts from standby conditions/steady state 3.8.1.2 4.7.A.1 Verify each DG is synchronized and loaded 3.8.1.3 4.7.A.1 Verify each day tank level 3.8.1.4 ---------------

Check for and remove accumulated water from day tank 3.8.1.5 ---------------

Verify fuel oil transfer system operates 3.8.1.6 ---------------

Verify each DG starts from standby conditions/quick start 3.8.1.7 ---------------

Verify transfer of power from offsite circuit to alternate circuit 3.8.1.8 ---------------

Verify DG rejects load greater than single largest load 3.8.1.9 ---------------

Verify DG maintains load following load reject 3.8.1.10 ---------------

Verify on loss of offsite power signal 3.8.1.11 ---------------

Verify DG starts on ECCS initiation signal 3.8.1.12 ---------------

Verify DG automatic trips bypassed on ECCS initiation signal 3.8.1.13 ---------------

Verify each DG operates for > 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 3.8.1.14 ---------------

Verify each DG starts from standby conditions/quick restart 3.8.1.15 ---------------

Verify each DG synchronizes with offsite power 3.8.1.16 ---------------

Verify ECCS initiation signal overrides test mode 3.8.1.17 ---------------

Verify interval between each timed load block 3.8.1.18 ---------------

Verify on LOOP in conjunction with ECCS initiation signal 3.8.1.19 ---------------

Verify simultaneous DG starts 3.8.1.20 4.7.A.2 Diesel Generator Starting Batteries ----------- 4.7.B Verify electrolyte level, pilot cell voltage, battery voltage on float ----------- 4.7.B.1 charge, pilot cell specific gravity Specific gravity and electrolyte temperature for each fourth cell ----------- 4.7.B.2 Specific gravity and electrolyte temperature for every cell ----------- 4.7.B.3 Battery capacity during battery service test ----------- 4.7.B.4 Battery capacity during battery discharge test ----------- 4.7.B.5

LAR - Adoption of TSTF-425, Revision 3 Attachment 4 Docket No. 50-219 Page 9 of 10 Technical Specification Section Title/Surveillance Description* TSTF-425 OCNGS Diesel Fuel Oil, Lube Oil, and Starting Air 3.8.3 ---------------

Verify fuel oil storage tank volume 3.8.3.1 ---------------

Verify lube oil inventory 3.8.3.2 ---------------

Verify each DG air start receiver pressure 3.8.3.4 ---------------

Check/remove accumulated water from fuel oil storage tank 3.8.3.5 ---------------

DC Sources - Operating/Battery Parameters 3.8.4/3.8.6 4.7.C Verify battery terminal voltage 3.8.4.1 4.7.C.1.a Verify each battery charger supplies amperage 3.8.4.2 ---------------

Verify battery capacity during battery service test 3.8.4.3 4.7.C.4 Verify battery capacity during performance discharge test 3.8.6.6 4.7.C.5 Verify battery float current 3.8.6.1 4.7.C.1.b Verify battery pilot cell voltage 3.8.6.2 4.7.C.2.b Verify battery connected cell electrolyte level 3.8.6.3 4.7.C.2.a Verify battery pilot cell temperature 3.8.6.4 4.7.C.2.c Verify battery connected cell voltage 3.8.6.5 4.7.C.3 Inverters - Operating 3.8.7 ---------------

Verify correct inverter voltage, frequency and alignment 3.8.7.1 ---------------

Inverters - Shutdown 3.8.8 ---------------

Verify correct inverter voltage, frequency and alignment 3.8.8.1 ---------------

Distribution System - Operating 3.8.9 ---------------

Verify correct breaker alignment/power to distribution subsystems 3.8.9.1 ---------------

Distribution System - Shutdown 3.8.10 ---------------

Verify correct breaker alignment/power to distribution subsystems 3.8.10.1 ---------------

Refueling Equipment Interlocks 3.9.1 4.9.A Channel Functional Test of refueling equip interlock inputs 3.9.1.1 4.9.A SRMs (Refueling) ---------- 4.9.B SRMs checked, tested, and calibrated ---------- 4.9.B Refuel Position One-Rod-Out Interlock 3.9.2 4.9.D Verify reactor mode switch locked in refuel position 3.9.2.1 4.9.D.1 Perform Channel Functional Test 3.9.2.2 4.9.D.1 Control Rod Position 3.9.3 ---------------

Verify all control rods fully inserted 3.9.3.1 ---------------

Control Rod Operability - Refuel 3.9.5 ---------------

Insert each withdrawn control rod one notch 3.9.5.1 ---------------

Verify each withdrawn control rod scram accumulator press 3.9.5.2 ---------------

Reactor Pressure Vessel (RPV) Water Level - Irradiated Fuel/New 3.9.6/3.9.7 ---------------

Fuel Verify RPV water level 3.9.6.1/ ---------------

3.9.7.1 RHR - High Water Level 3.9.8 ---------------

Verify one RHR shutdown cooling subsystem operating 3.9.8.1 ---------------

RHR - Low Water Level 3.9.9 ---------------

Verify one RHR shutdown cooling subsystem operating 3.9.9.1 ---------------

Reactor Mode Switch Interlock Testing 3.10.2 ---------------

Verify all control rods fully inserted in core cells 3.10.2.1 ---------------

Verify no core alterations in progress 3.10.2.2 ---------------

LAR - Adoption of TSTF-425, Revision 3 Attachment 4 Docket No. 50-219 Page 10 of 10 Technical Specification Section Title/Surveillance Description* TSTF-425 OCNGS Single Control Rod Withdrawal - Hot Shutdown 3.10.3 ---------------

Verify all control rods in five-by-five array are disarmed 3.10.3.2 ---------------

Verify all control rods other than withdrawn rod are fully inserted 3.10.3.3 ---------------

Single Control Rod Withdrawal - Cold Shutdown 3.10.4 ---------------

Verify all control rods in five-by-five array are disarmed 3.10.4.2 ---------------

Verify all control rods other than withdrawn rod are fully inserted 3.10.4.3 ---------------

Verify a control rod withdrawal block is inserted 3.10.4.4 ---------------

Single Control Rod Drive (CRD) Removal - Refuel 3.10.5 4.9.D Verify all control rods other than withdrawn rod are fully inserted 3.10.5.1 4.9.D.3 Verify all control rods in five-by-five array are disarmed 3.10.5.2 ---------------

Verify a control rod withdrawal block is inserted 3.10.5.3 ---------------

Verify no core alterations in progress 3.10.5.5 ---------------

Multiple CRD Removal-Refuel 3.10.6 4.9.D Verify four fuel assemblies removed from core cells 3.10.6.1 4.9.D.4 Verify all other rods in core cells inserted 3.10.6.2 4.9.D.3 Verify fuel assemblies being loaded comply with reload sequence 3.10.6.3 ---------------

Scram Discharge Margin Test - Refueling 3.10.8 ---------------

Verify no other core alterations in progress 3.10.8.4 ---------------

Verify CRD charging water header pressure 3.10.8.6 ---------------

Recirculation Loops - Testing 3.10.9 ---------------

Verify LCO 3.4.1 requirements suspended for < 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 3.10.9.1 ---------------

Verify Thermal power < 5% RTP during Physics Test 3.10.9.2 ---------------

Training Startups 3.10.10 ---------------

Verify all operable IRM channels are <25/40 div. of full scale 3.10.10.1 ---------------

Verify average reactor coolant temperature < 200 F 3.10.10.2 ---------------

Radioactive Liquid Storage ----------- 4.6.C Liquids contained in tanks sampled and analyzed ----------- 4.6.C.1 Programs (Surveillance Frequency Control Program [SFCP]) 5.5.15 6.24

  • The Technical Specification Section Title/Surveillance Description portion of this attachment is a summary description of the referenced TSTF-425 (NUREG-1433)/OCNGS TS Surveillances which is provided for information purposes only and is not intended to be a verbatim description of the TS Surveillances.

ATTACHMENT 5 License Amendment Request Oyster Creek Nuclear Generating Station Docket No. 50-219 Application for Technical Specification Change Regarding Risk-Informed Justification for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program (Adoption of TSTF-425, Revision 3)

Proposed No Significant Hazards Consideration

LAR - Adoption of TSTF-425, Revision 3 Attachment 5 Docket No. 50-219 Page 1 of 2 PROPOSED NO SIGNIFICANT HAZARDS CONSIDERATION Description of Amendment Request: This amendment request involves the adoption of approved changes 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 changes are described in Technical Specification Task Force (TSTF) Traveler, TSTF-425, Revision 3 (ADAMS Accession No. ML090850642) related to the Relocation of Surveillance Frequencies to Licensee Control - RITSTF Initiative 5b and are described in the Notice of Availability published in the Federal Register on July 6, 2009 (74 FR 31996).

The proposed changes are consistent with NRC-approved Industry/ TSTF Traveler, TSTF-425, Revision 3, "Relocate Surveillance Frequencies to Licensee Control - RITSTF Initiative 5b.

The proposed changes relocate surveillance frequencies to a licensee-controlled program, the Surveillance Frequency Control Program (SFCP). The changes are applicable to licensees using probabilistic risk guidelines contained in NRC-approved NEI 04-10, "Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies, (ADAMS Accession No. 071360456).

Basis for proposed no significant hazards consideration: As required by 10 CFR 50.91(a),

the Exelon analysis of the issue of no significant hazards consideration is presented below:

1. Do the proposed changes involve a significant increase in the probability or consequences of any accident previously evaluated?

Response: No.

The proposed changes relocate the specified frequencies for periodic surveillance requirements to licensee control under a new Surveillance Frequency Control Program.

Surveillance frequencies are not an initiator to any accident previously evaluated. As a result, the probability of any accident previously evaluated is not significantly increased. The systems and components required by the technical specifications for which the surveillance frequencies are relocated are still required to be operable, meet the acceptance criteria for the surveillance requirements, and be capable of performing any mitigation function assumed in the accident analysis. As a result, the consequences of any accident previously evaluated are not significantly increased.

Therefore, the proposed changes do not involve a significant increase in the probability or consequences of an accident previously evaluated.

2. Do the proposed changes create the possibility of a new or different kind of accident from any previously evaluated?

Response: No.

No new or different accidents result from utilizing the proposed changes. The changes do not involve a physical alteration of the plant (i.e., no new or different type of equipment will be installed) or a change in the methods governing normal plant operation. In addition, the

LAR - Adoption of TSTF-425, Revision 3 Attachment 5 Docket No. 50-219 Page 2 of 2 changes do not impose any new or different requirements. The changes do not alter assumptions made in the safety analysis. The proposed changes are consistent with the safety analysis assumptions and current plant operating practice.

Therefore, the proposed changes do not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Do the proposed changes involve a significant reduction in the margin of safety?

Response: No.

The design, operation, testing methods, and acceptance criteria for systems, structures, and components (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, Exelon will perform a probabilistic risk evaluation using the guidance contained in NRC approved NEI 04-10, Rev. 1, in accordance with the TS 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.

Therefore, the proposed changes do not involve a significant reduction in a margin of safety.

Based upon the above, Exelon concludes that the requested changes do not involve a significant hazards consideration as set forth in 10 CFR 50.92(c), "Issuance of Amendment."

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