Text

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)
	ML100480339
Person / Time
Site:	Quad Cities
Issue date:	02/16/2010
From:	Hansen J; Exelon Corp, Exelon Generation Co, Exelon Nuclear
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	RS-10-032
	Download: ML100480339 (347)
	v • d • e

Exelon Generation www .exeloncorp .co m 4300 Winfield Road WarTenville, I L 60555 10 CF 50.90

!110032 February 16, 2010 U .S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555 Quad Cities Nuclear Power Station, Units 1 and 2 Renewed Facility Operating License Nos. DPR-29 and DPR-30 NRC Docket Nos. 50-254 and 50-265

Subject:

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)

References : 1 . Nuclear Energy Institute (NEI) 04-10, "Risk-informed Technical Specifications Initiative 5b, Risk-informed Method for Control of Surveillance Frequencies,"

Revision 1, April 2007 2 . Technical Specifications Task Force (TSTF) Standard Technical Specifications (STS) Change TSTF-425, "Relocate Surveillance Frequencies to Licensee Control - RITSTF Initiative 5b," Revision 3, dated March 18, 2009

3. "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," Federal Register published July 6, 2009 (74 FR 31996)

In accordance with 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit," Exelon Generation Company, LLC (EGC) requests an amendment to Appendix A, Technical Specifications (TS) of Renewed Facility Operating License Nos. CPR-29 and DPR-30 for Quad Cities Nuclear Power Station (QCNPS), Units 1 and 2, respectively . The proposed amendment would modify the QCNPS 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 ethod for Control of Surveillance Frequencies," Revision 1 (i.e., Reference 1).

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

Standard Technical Specifications ( ) change TSTF-425, "Relocate Surveillance Frequencies Licens 5b," Revision 3 (i .e., Referenc scus

February 16, 2010 U.S . Nuclear Regulatory Commission Page 2 The Federal Register notice that was published on July 6, 2009 (i .e., Reference 3), announced the availability of this TS improvement as part of the consolidated line item improvement process (CLI I P).

This request is subdivided as follows :

Attachment 1 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 marked-up QCNPS, Unit 1 and Unit 2 TS pages with the proposed changes indicated.

Attachment 4 provides the marked-up QCNPS, Unit 1 and Unit 2 TS Bases pages with the proposed changes indicated . The TS Bases pages are provided for information only and do not require NRC approval .

Attachment 5 provides a TSTF-425 (NUREG-1433) versus QCNPS TS cross-reference .

Attachment 6 provides the proposed No Significant Hazards Consideration .

The proposed change has been reviewed by the QCNPS Plant Operations Review Committee and approved by the Nuclear Safety Review Board in accordance with the requirements of the EGC Quality Assurance Program .

EGC requests approval of the proposed license amendment by February 16, 2011 . Once approved, the amendment will be implemented within 120 days . This implementation period will provide adequate time for the affected station documents to be revised using the appropriate change control mechanisms .

In accordance with 10 CFR 50.91, "Notice for public comment; State consultation,"

paragraph (b), EGC is notifying the State of Illinois of this application for license amendment by transmitting a copy of this letter and its attachments to the designated State Official.

There are no regulatory commitments contained in this letter . Should you have any questions concerning this letter, please contact fir. John L. Schrage at (630) 657-2821 .

February 16, 2010 U.S . Nuclear Regulatory Commission Page 3 I declare under penalty of perjury that the foregoing is true and correct. Executed on the 16th day of February 2010.

Respectfully, Jeffrey-L. Hansen Manager - Licensing Attachments: 1 - Evaluation of Proposed Changes

2. Documentation of PRA Technical Adequacy

3. Proposed Technical Specification Page Changes

4. Proposed Technical Specification Bases Page Changes (for information only)

5. TSTF-425 (NUREG-1433) vs . QCNPS Cross-Reference EV Proposed No Significant Hazards Consideration

ATTACHMENT 1 Evaluation of Proposed Changes

1.0 DESCRIPTION

2.0 ASSESSMENT 2.1 Applicability of Published Safety Evaluation 2.2 Optional Changes and Variations

3.0 REGULATORY ANALYSIS

3.1 No Significant Hazards Consideration 3.2 Applicable Regulatory Requirements 3.3 Conclusions

4.0 ENVIRONMENTAL CONSIDERATION

5.0 REFERENCES

Page 1 of 5

ATTACHMENT 1 Evaluation of Proposed Changes

1.0 DESCRIPTION

The proposed amendment would modify the Quad Cities Nuclear Power Station (QCNPS),

Units 1 and 2, Technical Specifications (TS) by relocating specific surveillance frequencies to a licensee-controlled program with the adoption of Technical Specification Task Force (TSTF) -

425, "Relocate Surveillance Frequencies to Licensee Control - Risk Informed Technical Specification Task Force (RITSTF) Initiative 5b," Revision 3 (TSTF-425). Additionally, the change would add a new program, the "Surveillance Frequency Control Program" (SFCP), to TS Section 5, "Administrative Controls."

The proposed changes are consistent with NRC-approved TSTF Standard Technical Specifications (STS) change TSTF-425 (ADAMS Accession No. ML090850642). The Federal Register notice published on July 6, 2009 (74 FR 31996), announced the availability of this TS improvement as part of the Consolidated Line Item Improvement Process (CLIIP). The changes are applicable to licensees using probabilistic risk guidelines contained in NRC-approved Nuclear Energy Institute (NEI) 04-10, "Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies, Revision 1, dated April 2007 (NEI 04-10) (ADAMS Accession No. 071360456).

2.0 ASSESSMENT 2.1 Applicability of Published Safety Evaluation Exelon Generation Company, LLC (EGC) has reviewed the NRC safety evaluation (SE) dated July 6, 2009. This review included a review of the NRC's evaluation, TSTF-425, and the requirements specified in NEI 04-10. includes EGC's documentation with regard to Probabilistic Risk Assessment (PRA) technical adequacy, consistent with the requirements of Regulatory Guide 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, Revision 1 (ADAMS Accession No. ML070240001), Section 4.2. This includes the description of any PRA models without NRC-endorsed standards, including documentation of the quality characteristics of those models in accordance with Regulatory Guide 1.200.

EGC has concluded that the justifications presented in TSTF-425 and the corresponding NRC SE are applicable to QCNPS, Units 1 and 2, and justify this license amendment request (LAR) to incorporate the changes to the QCNPS TS.

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

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ATTACHMENT 1 Evaluation of Proposed Changes

1. Revised (clean) TS pages are not included in this LAR given the number of TS pages affected, the straightforward nature of the proposed changes, and outstanding QCNPS LARs that will impact some of the same TS pages. By providing only mark-ups of the proposed TS changes, EGC satisfies the requirements of 10 CFR 50.90 in that the mark-ups fully describe the changes desired. This is an administrative deviation from the NRCs model application dated July 6, 2009 (74 FR 31996) with no impact on the NRCs model SE published in the same Federal Register notice. As a result of this deviation, the contents and numbering of the attachments for this LAR differ from the attachments specified in the NRCs model application. Mark-ups of the proposed TS changes are provided in Attachment 3 for QCNPS, Units 1 and 2. Additionally, mark-ups of the proposed changes to TS Bases pages are provided in Attachment 4 for QCNPS, Units 1 and 2. The proposed changes to the TS Bases are provided for information only.

Changes to the Bases are incorporated in accordance with QCNPS Bases Control Program and, therefore, do not require NRC approval.

2. The insert provided in TSF-425 to replace text in the TS Bases describing the basis for each frequency relocated to the SFCP has been revised from, "The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program," to read "The Frequency may be based on factors such as operating experience, equipment reliability, or plant risk, and is controlled under the Surveillance Frequency Control Program." This deviation is necessary to reflect the QCNPS basis for frequencies which do not, in all cases, base frequency on operating experience, equipment reliability and plant risk.

3. Attachment 5 provides a cross-reference between the NUREG-1433 Surveillance Requirements (SRs) included in TSTF-425 versus the QCNPS SRs included in this LAR.

Attachment 5 includes a summary description of the referenced TSTF-425 (NUREG-1433)/QCNPS TS SRs which is provided for information purposes only and is not intended to be a verbatim description of the TS SRs. This cross-reference highlights the following:

a. NUREG-1433 SRs included in TSTF-425 and corresponding QCNPS SRs with identical SR numbers;

b. NUREG-1433 SRs included in TSTF-425 and corresponding QCNPS SRs with differing SR numbers;

c. NUREG-1433 SRs included in TSTF-425 that are not contained in the QCNPS TS; and

d. QCNPS plant-specific SRs that are not contained in NUREG-1433, and therefore, are not included in the TSTF-425 mark-ups.

Concerning the above, QCNPS SRs that have SR numbers identical to the corresponding NUREG-1433 SRs are not deviations from TSTF-425.

QCNPS SRs with SR numbers that differ from the corresponding NUREG-1433 SRs are administrative deviations from TSTF-425 with no impact on the NRCs model SE dated July 6, 2009 (74 FR 31996).

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ATTACHMENT 1 Evaluation of Proposed Changes For NUREG-1433 SRs that are not contained in the QCNPS TS, the corresponding NUREG-1433 mark-ups included in TSTF-425 for these SRs are not applicable to QCNPS. This is an administrative deviation from TSTF-425 with no impact on the NRCs model SE dated July 6, 2009 (74 FR 31996).

For QCNPS plant-specific SRs that are not contained in NUREG-1433, and therefore, are not included in the NUREG-1433 mark-ups provided in TSTF-425, EGC has determined that the relocation of the Frequencies for these QCNPS plant-specific SRs is consistent with the intent of TSTF-425, Revision 3, and with the NRC's model SE dated July 6, 2009 (74 FR 31996), including the scope exclusions identified in Section 1.0, "Introduction," of the model SE, because the subject plant-specific SRs involve fixed periodic Frequencies.

In accordance with TSTF-425, changes to the frequencies for these SRs would be controlled under the SFCP. The SFCP provides the necessary administrative controls to require that SRs related to testing, calibration and inspection are conducted at a frequency to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met. Changes to frequencies in the SFCP would be evaluated using the methodology and probabilistic risk guidelines contained in Reference 3, as approved by NRC letter dated September 19, 2007 (ADAMS Accession No. ML072570267).

The NEI 04-10 methodology includes qualitative considerations, risk analyses, sensitivity studies and bounding analyses, as necessary, and recommended monitoring of the performance of systems, components, and structures (SSCs) for which Frequencies are changed to assure that reduced testing does not adversely impact the SSCs. In addition, the NEI 04-10, Revision 1 methodology satisfies the five key safety principles specified in Regulatory Guide 1.177, An Approach for Plant-Specific, Risk-Informed Decisionmaking:

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

relative to changes in Surveillance Frequencies.

3.0 REGULATORY ANALYSIS

3.1 No Significant Hazards Consideration EGC has reviewed the proposed No Significant Hazards Consideration (NSHC) determination published in the Federal Register dated July 6, 2009 (74 FR 31996). EGC has concluded that the proposed NSHC presented in the Federal Register notice is applicable to QCNPS, Units 1 and 2, and is provided as Attachment 6 to this amendment request, which satisfies the requirements of 10 CFR 50.91(a).

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ATTACHMENT 1 Evaluation of Proposed Changes 3.2 Applicable Regulatory Requirements A description of the proposed changes and their relationship to applicable regulatory requirements is provided in TSTF-425, Revision 3 (ADAMS Accession No. ML090850642) and the NRCs model SE published in the Notice of Availability dated July 6, 2009 (74 FR 31996).

EGC has concluded that the relationship of the proposed changes to the applicable regulatory requirements presented in the Federal Register notice is applicable to QCNPS, Units 1 and 2.

3.3 Conclusions In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commissions regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

4.0 ENVIRONMENTAL CONSIDERATION

EGC has reviewed the environmental consideration included in the NRCs model SE published in the Federal Register on July 6, 2009 (74 FR 31996). EGC has concluded that the NRCs findings presented therein are applicable to QCNPS, Units 1 and 2, and the determination is hereby incorporated by reference for this application.

5.0 REFERENCES

1. TSTF-425, "Relocate Surveillance Frequencies to Licensee Control - RITSTF Initiative 5b,

Revision 3, 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," Federal Register notice published on July 6, 2009 (74 FR 31996).

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

4. Regulatory Guide 1.200, Revision 1, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, January 2007 (ADAMS Accession Number: ML070240001).

5. Regulatory Guide 1.177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking:

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

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ATTACHMENT 2 Documentation of Probabilistic Risk Assessment Technical Adequacy TABLE OF CONTENTS Section Page 2.1 OVERVIEW....................................................................................................................... 2 2.2 TECHNICAL ADEQUACY OF THE PRA MODEL ........................................................... 3 2.2.1 PLANT CHANGES NOT YET INCORPORATED INTO THE PRA MODEL.......... 5 2.2.2 APPLICABILITY OF PEER REVIEW FINDINGS AND OBSERVATIONS ............ 5 2.2.3 CONSISTENCY WITH APPLICABLE PRA STANDARDS.................................... 6 2.2.4 IDENTIFICATION OF KEY ASSUMPTIONS....................................................... 16 2.3 EXTERNAL EVENTS CONSIDERATIONS .................................................................... 16 2.4

SUMMARY

...................................................................................................................... 17

2.5 REFERENCES

................................................................................................................ 18 Page 1 of 18

ATTACHMENT 2 Documentation of Probabilistic Risk Assessment Technical Adequacy Documentation of Probabilistic Risk Assessment Technical Adequacy 2.1 Overview The implementation of the Surveillance Frequency Control Program (also referred to as Technical Specification (TS) Initiative 5b) at Quad Cities Nuclear Power Station (QCNPS) will follow the guidance provided in NEI 04-10, Revision 1 (Reference 1) in evaluating proposed surveillance test interval (STI) 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 (Reference 1).

Each STI revision is reviewed by an Expert Panel, referred to as the Integrated Decision-making Panel (IDP), which is normally the same panel 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 implemented and documented 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 Figure 2 of NEI 04-10. Also, the cumulative impact of all risk-informed STI revisions on all hazards which have a PRA model (i.e., internal events, external events and shutdown) is also compared to the risk acceptance criteria as delineated in NEI 04-10.

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ATTACHMENT 2 Documentation of Probabilistic Risk Assessment Technical Adequacy 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 1.200, Revision 1 (Reference 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:

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 and external), identify appropriate compensatory measures or provide bounding arguments to address the risk contributors not addressed by the 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, in RG-1.200 Revision 1 this is just the internal events PRA standard). Provide justification to show that where specific requirements in the standard are not adequately met, it will not unduly impact the results.

Identify key assumptions and approximations relevant to the results used in the decision-making process.

Because of the broad scope of potential Initiative 5b applications and the fact that the impact of such assumptions differs from application to application, each of the issues encompassed in Items 1 through 3 will be covered with the preparation of each individual PRA assessment made in support of the individual STI interval requests. The purpose of the remaining portion of this appendix is to address the requirements identified in item 4 above.

2.2 Technical Adequacy of the PRA Model The 2005B update to the QCNPS PRA model is the most recent evaluation of the risk profile at QCNPS for internal event challenges. The QCNPS PRA modeling is highly detailed, including a Page 3 of 18

ATTACHMENT 2 Documentation of Probabilistic Risk Assessment Technical Adequacy wide variety of initiating events, modeled systems, operator actions, and common cause events.

The PRA model quantification process used for the QCNPS PRA is based on the event tree /

fault tree methodology, which is a well-known methodology in the industry.

Exelon Generation Company (EGC) employs a multi-faceted approach to establishing and maintaining the technical adequacy and plant fidelity of the PRA models for all operating EGC 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 QCNPS PRA.

PRA Maintenance and Update The EGC risk management process ensures that the applicable PRA model remains an accurate reflection of the as-built and as-operated plants. This process is defined in the EGC Risk Management program, which consists of a governing procedure (ER-AA-600, "Risk Management") and subordinate implementation procedures. EGC 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 EGC nuclear generation sites. The overall EGC 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, errors or limitations identified in the model, industry operating experience), and for controlling the model and associated computer files. To ensure that the current PRA model remains an accurate reflection of the as-built, as-operated plants, 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, EGC risk management procedures provide the guidance for particular risk management and PRA quality and maintenance activities. This guidance includes:

Documentation of the PRA model, PRA products, and 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 EGC 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 systems, structures, and components (SSCs) within the scope of the Maintenance Rule (10CFR50.65 (a)(4)).

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ATTACHMENT 2 Documentation of Probabilistic Risk Assessment Technical Adequacy 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. EGC is scheduled for a regular update to the QCNPS PRA model in 2010, which is expected to be approved by the end of 2010.

As indicated previously, RG 1.200 also requires that additional information be provided as part of the LAR submittal to demonstrate the technical adequacy of the PRA model used for the risk assessment. Each of these items (plant changes not yet incorporated in to the PRA model, relevant peer review findings, consistency with applicable PRA Standards, and the identification of key assumptions) will be discussed in turn.

2.2.1 Plant Changes Not Yet Incorporated into the PRA Model A PRA updating requirements evaluation (URE- EGC 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 part of the PRA evaluation for each STI change request, a review of open items in the URE database for QCNPS 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 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 QCNPS 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 February 2000 (Reference 3), following the Industry PRA Peer Review process (Reference 4). This peer review included an assessment of the PRA model maintenance and update process.

In 2004, prior to the 2005 PRA update, a self-assessment analysis was performed against the available version of the ASME PRA Standard, Addendum A (Reference 5).

During 2005 and 2006, the QCNPS 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.

In 2009, an update of the self-assessment analysis was performed against ASME PRA Standard, Addendum B (Reference 5). The 2009 self-assessment also addresses the updated Supporting Requirements associated with PRA Model Uncertainty as provided in the Combined PRA Standard (Reference 6) and Regulatory Guide 1.200, Revision 2 (Reference 7).

A summary of the disposition of the 2000 Industry PRA Peer Review Facts and Observations (F&Os) for the QCNPS PRA models was documented as part of the statement of PRA capability for MSPI in the QCNPS MSPI Basis Document (Reference 8). As noted in that document, there Page 5 of 18

ATTACHMENT 2 Documentation of Probabilistic Risk Assessment Technical Adequacy were no significance level A F&Os from the peer review, and all significance level B F&Os were addressed and closed out with the completion of the current model of record (2005B). Also noted in that submittal was the fact that, after allowing for plant-specific features, there are no MSPI cross-comparison outliers for QCNPS (refer to the third bulleted item above).

A Gap Analysis (i.e., self-assessment) for the QCNPS PRA model was completed in 2004. This Gap Analysis was performed against the ASME PRA Standard, Addendum A (Reference 5).

The 2004 gap analysis defined a list of 85 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 updating requirements evaluation (URE) (EGC model update tracking database) was documented for resolution.

A PRA model update was completed in 2005. 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 model and the updated requirements in Addendum B of the ASME PRA Standard concluded that 69 of the gaps were fully resolved (i.e., are no longer gaps), and another one (1) was partially resolved.

After accounting for the number of Supporting Requirements added or deleted as part of Addendum B, the QCNPS PRA contains 21 potential gaps to Capability Category II of the Standard.

2.2.3 Consistency with Applicable PRA Standards As indicated above, a PRA model update was completed in 2005, resulting in the 2005B updated model. In updating the PRA, changes were made to the PRA to address most of the identified gaps, as well as to address other open UREs. The updated results of the 2009 self-assessment status based on comparison to the most recently available information as described above are summarized in Table 2.2-1 along with an assessment of the impact for this application.

All remaining gaps will be reviewed for consideration during the next model update 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.

Additionally, the remaining gaps 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 model changes to confirm the impact on the risk analysis.

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ATTACHMENT 2 Documentation of Probabilistic Risk Assessment Technical Adequacy TABLE 2.2-1 STATUS OF IDENTIFIED GAPS TO CAPABILITY CATEGORY II OF THE ASME PRA STANDARD TITLE DESCRIPTION OF GAP APPLICABLE CURRENT STATUS COMMENT SUPPORTING REQUIREMENTS Gap #1 Reaching a safe stable end state defines the SC-A5 Open. Enhance The current approach is judged success of a sequence and therefore the documentation to justify why to be reasonable for long term mission time of the sequence to achieve the extending FTR mission times scenarios (e.g., long term loss Level 1 end state. The mission times for beyond 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for loss of of DHR). This would be failure to run calculations are assessed at 24 DHR sequences is not addressed by sensitivities per hours or less if specifically justified. necessary. The NEI 04-10 if applicable to the Extending the FTR mission time beyond 24 considerations that support the specific STI evaluation.

hours for loss of DHR sequences is choice of the mission time are considered to be an unnecessary as follows:

complication and does not affect PRA Equipment failure rates insights nor does it significantly affect its (failures/hour) are judged to be quantitative evaluation. too conservative for times greater than a few hours of operation.

For times greater than a few hours, the ability to repair and recover equipment can compete with the failure rate such that there can be considered to be a steady state equilibrium condition reached.

Gap #2 Strict interpretation of SY-A12 would require SY-A12 Open. Enhance Not significant. The PRA additional investigation in determining documentation to justify why model is judged to include whether all appropriate components and certain components and failure proper treatment of failure modes are included could be modes may be excluded. components and failure modes performed. for Capability Category II requirements.

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ATTACHMENT 2 Documentation of Probabilistic Risk Assessment Technical Adequacy TABLE 2.2-1 STATUS OF IDENTIFIED GAPS TO CAPABILITY CATEGORY II OF THE ASME PRA STANDARD TITLE DESCRIPTION OF GAP APPLICABLE CURRENT STATUS COMMENT SUPPORTING REQUIREMENTS Gap #3 Document the criteria for how components SY-A14 Open. Enhance Not significant. The PRA and failure modes may be excluded from the documentation to justify why model is judged to include model (e.g., failure mode is less than 1% of certain components and failure proper treatment of the total failure probability for that modes may be excluded. components and failure modes component). for Capability Category II requirements.

Gap #4 Investigate to determine whether the SY-B11 Open. Enhance The NEI 04-10 process initiation logic for systems other than ECCS documentation to justify why requires modification of the and RCIC should be modeled. initiation logic is not required PRA model if needed to assess Note that initiation logic for the EDGs could to be modeled for all systems a STI change.

be modeled if the EDG failure data does not with automatic initiation.

already take into account failure of the automatic initiation instrumentation.

Gap #5 Strict interpretation of SY-C2 would require SY-C2 Open. Enhance the System This is judged to be a the following in the System Notebooks: Notebook documentation to documentation consideration References to the data notebook of the provide more transparency. only and does not affect the actual operating history indicating any past technical adequacy of the PRA problems with system operation model.

Relationship between system success criteria and accident sequences modeled A listing of components and failure modes included in the model and justification for any exclusions Results of the system model evaluation.

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ATTACHMENT 2 Documentation of Probabilistic Risk Assessment Technical Adequacy TABLE 2.2-1 STATUS OF IDENTIFIED GAPS TO CAPABILITY CATEGORY II OF THE ASME PRA STANDARD TITLE DESCRIPTION OF GAP APPLICABLE CURRENT STATUS COMMENT SUPPORTING REQUIREMENTS Gap #6 Although this will not significantly impact the HR-D3 Open. Possible upgrade to This would be addressed by HRA results, future PRA updates should the pre-initiator HRA to include sensitivities per NEI 04-10 if include an assessment of the quality of plant specific quantifications for applicable to the specific STI written procedures and administrative each pre-initiator HEP would evaluation.

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

Gap #7 Employ and document the methodology DA-C6 Open. A detailed The PRA model is judged to used for determining the standby component determination is judged to appropriately estimate the number of demands to include plant specific: require a significant level of number of demands for surveillance tests resources with marginal standby equipment for quantitative benefit. An calculating the failure maintenance acts estimate of the number of probabilities which will be surveillance tests or maintenance on other demands based on a review of acceptable for most STI components surveillance tests and other assessments. Additionally, the operational demands means is judged to be NEI 04-10 methodology Additional demands from post-maintenance sufficient. requires in Step 8 that an testing should not be included. 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.

Page 9 of 18

ATTACHMENT 2 Documentation of Probabilistic Risk Assessment Technical Adequacy TABLE 2.2-1 STATUS OF IDENTIFIED GAPS TO CAPABILITY CATEGORY II OF THE ASME PRA STANDARD TITLE DESCRIPTION OF GAP APPLICABLE CURRENT STATUS COMMENT SUPPORTING REQUIREMENTS Gap #8 Failure data developed should be based on DA-C7 Partially resolved. The failure The NEI 04-10 methodology plant surveillance actual practices (as data was based on actual requires in Step 8 that an opposed to plant requirements) and plant data. However, the appropriate time-related failure documented appropriately. Currently based number of demands and contribution be utilized in the on system engineer experience input. exposure data was based on STI change assessment and actual data or estimates from Step 14 requires that sensitivity the QCNPS System studies regarding the choice of Managers. that value be performed.

Gap #9 Standby failure data development should DA-C8 Open. The PRA model is judged to base the time that components were in appropriately estimate the time standby on plant operational records. This that components were in should be documented appropriately in the standby for calculating the Component Data Notebook (QC PSA-010). standby failure rate.

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.

Page 10 of 18

ATTACHMENT 2 Documentation of Probabilistic Risk Assessment Technical Adequacy TABLE 2.2-1 STATUS OF IDENTIFIED GAPS TO CAPABILITY CATEGORY II OF THE ASME PRA STANDARD TITLE DESCRIPTION OF GAP APPLICABLE CURRENT STATUS COMMENT SUPPORTING REQUIREMENTS Gap #10 Failure data development using surveillance DA-C10 Open. The surveillance test test data should fulfill the requirements of procedures are judged to DA-C10, and should be documented address the appropriate failure appropriately. Review surveillance test modes with respect to the procedures and identify all failure modes estimated number of demands.

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

Gap #11 No interviews of plant staff were performed DA-C12 Open. This deviation from the The model is consistent with to generate uncertainty estimates of Supporting Requirement is not data from the plant MR unavailability per maintenance act. considered to significantly alter database, so there will not be a An exception is taken to DA-C12. The plant the PRA qualitative or significant impact on staff does not have reasonable insights quantitative results. unavailability hours used in the applicable to the level of uncertainty model. This would be associated with the maintenance durations. addressed by sensitivities per Most plant staff have rotated positions and NEI 04-10 if applicable to the do not have sufficient longevity to provide specific STI evaluation.

this insight.

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ATTACHMENT 2 Documentation of Probabilistic Risk Assessment Technical Adequacy TABLE 2.2-1 STATUS OF IDENTIFIED GAPS TO CAPABILITY CATEGORY II OF THE ASME PRA STANDARD TITLE DESCRIPTION OF GAP APPLICABLE CURRENT STATUS COMMENT SUPPORTING REQUIREMENTS Gap #12 IF-B2 states to include human-induced IF-B2 Open. Update flood Using the pipe failure data from mechanisms that could lead to flooding frequencies to use EPRI TR- the latest EPRI report is judged events. 1013141, which is stated to to have a minor impact on the account for human-induced overall quantitative flood failure modes. results. This would be addressed by sensitivities per NEI 04-10 if applicable to the specific STI evaluation.

Gap #13 Add pressure and temperature IF-B3 Open. Judged to have a This is a documentation characteristics of flood water sources. negligible impact because consideration only not affecting most of the water sources in the technical adequacy of the the scope of the flooding PRA model.

analysis are low pressure and low temperature.

Gap #14 Evaluate and document the effects of check IF-C1 Open. Multiple check valve failures valve failure in drain lines leading to would be required to fail backflow. Backflow failures are discussed in multiple significant flood areas the QCNPS internal flood analysis (e.g., QC (e.g., ECCS corner rooms).

PSA-012, Section 2.2.11), however, the The dominant flood scenarios potential propagation paths should be (e.g., failure of long term documented in more detail. isolation) would flood multiple ECCS corner rooms and envelop the check valve backflow failure modes.

Page 12 of 18

ATTACHMENT 2 Documentation of Probabilistic Risk Assessment Technical Adequacy TABLE 2.2-1 STATUS OF IDENTIFIED GAPS TO CAPABILITY CATEGORY II OF THE ASME PRA STANDARD TITLE DESCRIPTION OF GAP APPLICABLE CURRENT STATUS COMMENT SUPPORTING REQUIREMENTS Gap #15 Document the potential for component IF-C3 Open. Jet impingement is This is judged to be a failure due to flooding induced jet judged to have a minor or documentation consideration impingement, humidity, condensation, and negligible quantitative impact. only not affecting the technical temperature concerns. adequacy of the PRA model.

High energy line breaks from the RPV have been evaluated as breaks outside containment. They have included an assessment of jet impingement, humidity, condensation, and temperature concerns.

Steam line break in the turbine building has not been addressed.

Gap #16 Evaluate and document the effects of check IF-C3b Open. Multiple check valve failures valve failure in drain lines leading to would be required to fail backflow. Backflow failures are discussed in multiple significant flood areas the QCNPS internal flood analysis (e.g., QC (e.g., ECCS corner rooms).

PSA-012, Section 2.2.11), however, the The dominant flood scenarios potential propagation paths should be (e.g., failure of long term documented in more detail. Identifying inter- isolation) would flood multiple area propagation is required to meet ECCS corner rooms and Capability Category II. envelop the check valve backflow failure modes. This would be addressed by sensitivities per NEI 04-10 if applicable to the specific STI evaluation.

Page 13 of 18

ATTACHMENT 2 Documentation of Probabilistic Risk Assessment Technical Adequacy TABLE 2.2-1 STATUS OF IDENTIFIED GAPS TO CAPABILITY CATEGORY II OF THE ASME PRA STANDARD TITLE DESCRIPTION OF GAP APPLICABLE CURRENT STATUS COMMENT SUPPORTING REQUIREMENTS Gap #17 IF-D6 states to include consideration of IF-D6 Open. Update flood Using the pipe failure data from human-induced floods during maintenance frequencies to use EPRI TR- the latest EPRI report is judged through application of generic data. 1013141 generic data, which to have a minor impact on the is stated to account for overall quantitative flood human-induced failure modes. results. This would be addressed by sensitivities per NEI 04-10 if applicable to the specific STI evaluation.

Gap #18 Maintenance alignments for the impact on IF-E4 Open. Update flood Using the pipe failure data from flood frequency may need to be addressed, frequencies to use EPRI TR- the latest EPRI report is judged via additional data analysis, if not adequately 1013141 generic data, which to have a minor impact on the covered in the pipe/component failure data. is stated to account for overall quantitative flood human-induced failure modes. results. This would be addressed by sensitivities per NEI 04-10 if applicable to the specific STI evaluation.

Gap #19 QU-F5 states to DOCUMENT limitations that QU-F5 Open. Plant specific The model is not used beyond would impact applications. limitations are expected to be its known limitations for PRA well defined in response to applications. This is a QU-F4 (i.e., Supporting documentation consideration Requirement for documenting only.

key assumptions and key sources of uncertainty).

Discuss and document the limitations of the model as they relate to future applications. (See QU-F4.).

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ATTACHMENT 2 Documentation of Probabilistic Risk Assessment Technical Adequacy TABLE 2.2-1 STATUS OF IDENTIFIED GAPS TO CAPABILITY CATEGORY II OF THE ASME PRA STANDARD TITLE DESCRIPTION OF GAP APPLICABLE CURRENT STATUS COMMENT SUPPORTING REQUIREMENTS Gap #20 Addendum B of the ASME PRA Standard QU-F6 Open - These new Supporting This is a documentation issue (Reference 5) added Supporting Requirements will be not affecting the technical Requirements to document the quantitative addressed during the next full adequacy of the PRA model.

definition used for significant basic event, PRA model update.

significant cutset, significant accident sequence, and significant accident progression sequence in the CDF and LERF analysis.

Gap #21 Addendum B of the ASME PRA Standard LE-G6 Open - These new Supporting This is a documentation issue (Reference 5) added Supporting Requirements will be not affecting the technical Requirements to document the quantitative addressed during the next full adequacy of the PRA model.

definition used for significant basic event, PRA model update.

significant cutset, significant accident sequence, and significant accident progression sequence in the CDF and LERF analysis.

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ATTACHMENT 2 Documentation of Probabilistic Risk Assessment Technical Adequacy 2.2.4 Identification of Key Assumptions The overall Initiative 5B process is a risk-informed process with the PRA model results providing one of the inputs to the IDP to determine if an STI change is warranted. The methodology recognizes that a key area of uncertainty for this application is the standby failure rate utilized in the determination of the STI extension impact. Therefore, the methodology requires the performance of selected sensitivity studies on the standby failure rate of the component(s) of interest for the STI assessment.

The results of the standby failure rate sensitivity study plus the results of any additional sensitivity studies identified during the performance of the reviews as outlined in 2.2.1 and 2.2.3 (including a review of identified sources of uncertainty developed for QCNPS consistent with the NUREG-1855 (Reference 9) and EPRI 1016737 (Reference 10) guidance for each STI change assessment will be documented and included in the results of the risk analysis that goes to the IDP.

2.3 External Events Considerations External hazards were evaluated in the QCNPS Individual Plant Examination of External Events (IPEEE) submittal in response to the NRC IPEEE Program (Generic Letter 88-20 Supplement 4). The IPEEE Program was a one-time review of external hazard risk and was limited in its purpose to the identification of potential plant vulnerabilities and the understanding of associated severe accident risks.

The results of the QCNPS IPEEE study are documented in the QCNPS IPEEE Main Report (Reference 11). The primary areas of external event evaluation at QCNPS were internal fire and seismic. The internal fire events were addressed by using the Fire Induced Vulnerability Evaluation (FIVE) methodology (Reference 12) and the seismic evaluations were performed in accordance with the EPRI Seismic Margins Analysis (SMA) methodology (Reference 13). As such, there are no realistic CDF and LERF values available from the IPEEE to support the STI risk assessment.

In addition to internal fires and seismic events, the QCNPS IPEEE analysis of high winds, external floods, and other external hazards was accomplished by reviewing the plant design and its environs against regulatory requirements regarding these hazards.

The Quad Cities plant design with respect to external flooding meets all the applicable criteria of the NRC Standard Review Plan (SRP) (Reference 14). Core damage accidents induced by external flooding are negligible contributors to plant risk.

Other external event risks such as severe weather, high winds or tornados, transportation accidents, nearby facility accidents, turbine missiles, and other miscellaneous external hazards were also considered in the IPEEE analysis (Reference 11). The NRC Standard Review Plan (SRP) (Reference 14) criteria have little applicability to Quad Cities, as the plant was built well before those criteria were formulated. However, it has been possible to demonstrate (e.g., via UFSAR analyses) that the plant has been specifically designed to withstand the postulated external events through recourse to bounding analyses and assessments, and by extensive margins built into the plant initially. It is judged that the other external events do not pose significant risk of severe accidents at Quad Cities. The compensatory actions and risk insights in this LAR are also judged applicable to qualitatively reduce the risk associated with these events.

Page 16 of 18

ATTACHMENT 2 Documentation of Probabilistic Risk Assessment Technical Adequacy The Quad Cities Seismic Margins Assessment and the FIVE methodology for fire risk assessment indicated that the plant was adequately designed and no vulnerabilities were found.

The NRC Staff Evaluation Report (SER) on the Quad Cities IPEEE (Reference 15) did not identify any commitments in order to meet the intent of the IPEEE. The conclusion of the SER states the following:

the staff notes that (1) the licensees IPEEE is complete with regard to the information requested by Supplement 4 to GL 88-20 (and associated guidance in NUREG-1407), and (2) the IPEEE results are reasonable given the Quad Cities design, operation, and history. Therefore, the staff concludes that the licensees IPEEE process is capable of identifying the most likely severe accidents and severe accident vulnerabilities, and therefore, that the Quad Cities IPEEE has met the intent of Supplement 4 to GL 88-20 and the resolution of specific generic safety issues discussed in this SER.

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.

Therefore, in performing the assessments for the other hazard groups, the qualitative or bounding approach will be utilized in most cases.

2.4 Summary The Quad Cities PRA maintenance and update processes and technical capability evaluations described above provide a robust basis for concluding that the PRA is suitable for use in risk-informed processes such as that proposed for the implementation of a Surveillance Frequency Control Program. As indicated above, 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.

Page 17 of 18

ATTACHMENT 2 Documentation of Probabilistic Risk Assessment Technical Adequacy 2.5 References

1. "Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies, Industry Guidance Document," NEI 04-10, Revision 1, April 2007.

2. Regulatory Guide 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk Informed Activities," Revision 1, January 2007.

3. Quad Cities Station PRA Peer Review, February 2000.

4. "Boiling Water Reactors Owners Group, BWROG PSA Peer Review Certification Implementation Guidelines," Revision 3, January 1997.

5. "Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications,"

(ASME RA-S-2002), Addenda RA-Sa-2003, and Addenda RA-Sb-2005, December 2005.

6. ASME/American Nuclear Society, "Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications," ASME/ANS RA-Sa-2009, March 2009.

7. Regulatory Guide 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment results for Risk-Informed Activities," Revision 2, March 2009.

8. Reactor Oversight Program MSPI Bases Document, Quad Cities Generating Station, Revision 4, February 2008.

9. U.S. Nuclear Regulatory Commission, "Guidance on the Treatment of Uncertainties Associated with PRAs in Risk-Informed Decision Making," NUREG-1855, Vol. 1, Main Report, March 2009.

10. "Treatment of Parameter and Model Uncertainty for Probabilistic Risk Assessments,"

EPRI, Palo Alto, CA: August 2008 (Draft). TR-1016737.

11. Quad Cities IPEEE Submittal Report, Revision 1, June 1999.

12. Professional Loss Control, Inc., "Fire-Induced Vulnerability Evaluation (FIVE)

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

13. NTS Engineering, et. al., "A Method for Assessment of Nuclear Power Plant Seismic Margin," EPRI NP-6041, Electric Power Research Institute, October 1988.

14. "Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants - LWR Edition," NUREG-75/087, December 1975.

15. U.S. Nuclear Regulatory Commission, Staff Evaluation Report of Quad Cities IPEEE, April 2001.

Page 18 of 18

ATTACHMENT 3 Markup of Proposed Technical Specifications Pages Quad Cities Nuclear Power Station, Units 1 and 2 Renewed Facility Operating License Nos. DPR-29 and DPR-30 REVISED TECHNICAL SPECIFICATION PAGES 1.1-5 3.3.5.1-8 3.5.2-3 3.7.2-2 3.8.7-3 1.1-6 3.3.5.1-9 3.5.2-4 3.7.3-1 3.8.8-2 3.1.3-4 3.3.5.2-3 3.5.3-2 3.7.4-3 3.9.1-2 3.1.4-2 3.3.6.1-4 3.5.3-3 3.7.5-2 3.9.2-1 3.1.5-3 3.3.6.2-3 3.6.1.1-2 3.7.6-2 3.9.2-2 3.1.6-2 3.3.6.3-2 3.6.1.2-4 3.7.7-1 3.9.3-1 3.1.7-2 3.3.7.1-3 3.6.1.3-5 3.7.7-2 3.9.5-1 3.1.7-3 3.3.7.2-3 3.6.1.3-6 3.7.8-1 3.9.6-1 3.1.8-2 3.3.8.1-2 3.6.1.3-7 3.7.9-1 3.9.7-1 3.2.1-1 3.3.8.2-2 3.6.1.4-1 3.7.9-2 3.9.8-3 3.2.2-1 3.4.1-2 3.6.1.5-1 3.8.1-6 3.9.9-3 3.2.3-1 3.4.2-1 3.6.1.6-2 3.8.1-7 3.10.1-2 3.3.1.1-3 3.4.3-2 3.6.1.7-2 3.8.1-8 3.10.2-3 3.3.1.1-4 3.4.4-2 3.6.1.7-3 3.8.1-9 3.10.3-3 3.3.1.1-5 3.4.5-3 3.6.1.8-2 3.8.1-10 3.10.3-4 3.3.1.1-6 3.4.6-2 3.6.2.1-3 3.8.1-11 3.10.4-2 3.3.1.2-3 3.4.7-3 3.6.2.2-1 3.8.1-12 3.10.4-3 3.3.1.2-4 3.4.8-2 3.6.2.3-2 3.8.1-13 3.10.5-2 3.3.1.2-5 3.4.9-3 3.6.2.4-2 3.8.1-14 3.10.7-3 3.3.1.3-3 3.4.9-4 3.6.2.5-2 3.8.1-15 3.10.7-4 3.3.2.1-4 3.4.9-5 3.6.3.1-1 3.8.3-2 5.5-13 3.3.2.1-5 3.4.10-1 3.6.4.1-2 3.8.4-4 3.3.2.2-3 3.5.1-4 3.6.4.2-4 3.8.4-5 3.3.3.1-3 3.5.1-5 3.6.4.3-3 3.8.4-6 3.3.4.1-3 3.5.1-6 3.7.1-2 3.8.6-3

Definitions 1.1 1.1 Definitions OPERABLE OPERABILITY are required for the system, subsystem, division, (continued) component, or device to perform its specified safety function(s) are also capable of performing their related support function(s).

RATED THERMAL POWER RTP shall be a total reactor core heat transfer (RTP) rate to the reactor coolant of 2957 MWt.

REACTOR PROTECTION The RPS RESPONSE TIME shall be that time interval SYSTEM (RPS) RESPONSE from the opening of the sensor contact until the TIME opening of the trip actuator. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured.

SHUTDOWN MARGIN (SDM) SDM shall be the amount of reactivity by which the reactor is subcritical or would be subcritical assuming that:

a. The reactor is xenon free;

b. The moderator temperature is 68°F; and

c. All control rods are fully inserted except for the single control rod of highest reactivity worth, which is assumed to be fully withdrawn.

With control rods not capable of being fully inserted, the reactivity worth of these control rods must be accounted for in the determination of SDM.

STAGGERED TEST BASIS A STAGGERED TEST BASIS shall consist of the testing of one of the systems, subsystems, channels, or other designated components during the interval specified by the Surveillance Frequency, so that all systems, subsystems, channels, or other designated components are (continued)

Quad Cities 1 and 2 1.1-5 Amendment No. 202/198

Definitions 1.1 1.1 Definitions STAGGERED TEST BASIS tested during n Surveillance Frequency intervals, (continued) where n is the total number of systems, subsystems, channels, or other designated components in the associated function.

THERMAL POWER THERMAL POWER shall be the total reactor core heat transfer rate to the reactor coolant.

TURBINE BYPASS SYSTEM The TURBINE BYPASS SYSTEM RESPONSE TIME shall be RESPONSE TIME that time interval from when the turbine bypass control unit generates a turbine bypass valve flow signal until the turbine bypass valves travel to their required positions. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured.

Quad Cities 1 and 2 1.1-6 Amendment No. 199/195

Control Rod OPERABILITY 3.1.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.3.1 Determine the position of each control rod. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months SR 3.1.3.2 DELETED SR 3.1.3.3 -------------------NOTE--------------------

Not required to be performed until 31 days after the control rod is withdrawn and THERMAL POWER is greater than the LPSP of the RWM.

Insert each withdrawn control rod at least 31 days one notch.

SR 3.1.3.4 Verify each control rod scram time from In accordance fully withdrawn to 90% insertion is with 7 seconds. SR 3.1.4.1, SR 3.1.4.2, SR 3.1.4.3, and SR 3.1.4.4 (continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.1.3-4 Amendment No. 244/239

Control Rod Scram Times 3.1.4 In accordance with the Surveillance Frequency SURVEILLANCE REQUIREMENTS Control Program SURVEILLANCE FREQUENCY SR 3.1.4.2 Verify, for a representative sample, each 120 days tested control rod scram time is within the cumulative limits of Table 3.1.4-1 with reactor steam operation in dome pressure 800 psig. MODE 1 SR 3.1.4.3 Verify each affected control rod scram time Prior to is within the limits of Table 3.1.4-1 with declaring any reactor steam dome pressure. control rod OPERABLE after work on control rod or CRD System that could affect scram time SR 3.1.4.4 Verify each affected control rod scram time Prior to is within the limits of Table 3.1.4-1 with exceeding reactor steam dome pressure 800 psig. 40% RTP after fuel movement within the affected core cell AND Prior to exceeding 40% RTP after work on control rod or CRD System that could affect scram time Quad Cities 1 and 2 3.1.4-2 Amendment No. 199/195

Control Rod Scram Accumulators 3.1.5 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. One or more control C.1 Verify all control Immediately upon rod scram accumulators rods associated with discovery of inoperable with inoperable charging water reactor steam dome accumulators are header pressure pressure < 900 psig. fully inserted. < 940 psig AND C.2 Declare the 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months associated control rod inoperable.

D. Required Action B.1 or D.1 --------NOTE---------

C.1 and associated Not applicable if all Completion Time not inoperable control met. rod scram accumulators are associated with fully inserted control rods.

Place the reactor Immediately mode switch in the shutdown position.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.5.1 Verify each control rod scram accumulator 7 days pressure is 940 psig.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.1.5-3 Amendment No. 199/195

Rod Pattern Control 3.1.6 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. Nine or more OPERABLE B.1 --------NOTE---------

control rods not in Rod worth minimizer compliance with the (RWM) may be bypassed analyzed rod position as allowed by sequence. LCO 3.3.2.1.

Suspend withdrawal of Immediately control rods.

AND B.2 Place the reactor 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months mode switch in the shutdown position.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.6.1 Verify all OPERABLE control rods comply 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months with the analyzed rod position sequence.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.1.6-2 Amendment No. 199/195

SLC System 3.1.7 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.7.1 Verify available volume of sodium 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months pentaborate solution is within the limits of Figure 3.1.7-1.

SR 3.1.7.2 Verify temperature of sodium pentaborate 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months solution is within the limits of Figure 3.1.7-2.

SR 3.1.7.3 Verify temperature of pump suction piping 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is 83°F.

SR 3.1.7.4 Verify continuity of explosive charge. 31 days SR 3.1.7.5 Verify the concentration of sodium 31 days pentaborate in solution is within the limits of Figure 3.1.7-1. AND Once within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after water or sodium pentaborate is added to solution AND Once within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after solution temperature is restored within the limits of Figure 3.1.7-2 (continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.1.7-2 Amendment No. 199/195

SLC System 3.1.7 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.7.6 Verify each SLC subsystem manual valve in 31 days the flow path that is not locked, sealed, or otherwise secured in position is in the correct position, or can be aligned to the correct position.

SR 3.1.7.7 Verify each pump develops a flow rate In accordance 40 gpm at a discharge pressure with the 1275 psig. Inservice Testing Program SR 3.1.7.8 Verify flow through one SLC subsystem from 24 months on a pump into reactor pressure vessel. STAGGERED TEST BASIS SR 3.1.7.9 Verify all heat traced piping between 24 months storage tank and pump suction is unblocked.

AND Once within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after piping temperature is restored within the limits of Figure 3.1.7-2 SR 3.1.7.10 Verify sodium pentaborate enrichment is Prior to

> 45.0 atom percent B-10. addition to SLC tank In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.1.7-3 Amendment No. 235/230

SDV Vent and Drain Valves 3.1.8 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.8.1 -------------------NOTE--------------------

Not required to be met on vent and drain valves closed during performance of SR 3.1.8.2.

Verify each SDV vent and drain valve is 31 days open.

SR 3.1.8.2 Cycle each SDV vent and drain valve to the 92 days fully closed and fully open position.

SR 3.1.8.3 Verify each SDV vent and drain valve: 24 months

a. Closes in 30 seconds after receipt of an actual or simulated scram signal; and

b. Opens when the actual or simulated scram signal is reset.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.1.8-2 Amendment No. 199/195

APLHGR 3.2.1 3.2 POWER DISTRIBUTION LIMITS 3.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)

LCO 3.2.1 All APLHGRs shall be less than or equal to the limits specified in the COLR.

APPLICABILITY: THERMAL POWER 25% RTP.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Any APLHGR not within A.1 Restore APLHGR(s) to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months limits. within limits.

B. Required Action and B.1 Reduce THERMAL POWER 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months associated Completion to < 25% RTP.

Time not met.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.2.1.1 Verify all APLHGRs are less than or equal Once within to the limits specified in the COLR. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after 25% RTP AND 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.2.1-1 Amendment No. 199/195

MCPR 3.2.2 3.2 POWER DISTRIBUTION LIMITS 3.2.2 MINIMUM CRITICAL POWER RATIO (MCPR)

LCO 3.2.2 All MCPRs shall be greater than or equal to the MCPR operating limits specified in the COLR.

APPLICABILITY: THERMAL POWER 25% RTP.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Any MCPR not within A.1 Restore MCPR(s) to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months limits. within limits.

B. Required Action and B.1 Reduce THERMAL POWER 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months associated Completion to < 25% RTP.

Time not met.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.2.2.1 Verify all MCPRs are greater than or equal Once within to the limits specified in the COLR. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after 25% RTP AND 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter (continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.2.2-1 Amendment No. 199/195

LHGR 3.2.3 3.2 POWER DISTRIBUTION LIMITS 3.2.3 LINEAR HEAT GENERATION RATE (LHGR)

LCO 3.2.3 All LHGRs shall be less than or equal to the limits specified in the COLR.

APPLICABILITY: THERMAL POWER 25% RTP.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Any LHGR not within A.1 Restore LHGR(s) to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months limits. within limits.

B. Required Action and B.1 Reduce THERMAL POWER 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months associated Completion to < 25% RTP.

Time not met.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.2.3.1 Verify all LHGRs are less than or equal to Once within the limits specified in the COLR. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after 25% RTP AND 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.2.3-1 Amendment No. 199/195

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS

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

1. Refer to Table 3.3.1.1-1 to determine which SRs apply for each RPS Function.

2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains RPS trip capability.

SURVEILLANCE FREQUENCY SR 3.3.1.1.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.1.1.2 ------------------NOTE-------------------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER 25% RTP.

Verify the absolute difference between 7 days the average power range monitor (APRM) channels and the calculated power is 2% RTP.

SR 3.3.1.1.3 Adjust the channel to conform to a 7 days calibrated flow signal.

(continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.3.1.1-3 Amendment No. 202/198

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.1.1.4 ------------------NOTE-------------------

Not required to be performed when entering MODE 2 from MODE 1 until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering MODE 2.

Perform CHANNEL FUNCTIONAL TEST. 7 days SR 3.3.1.1.5 Perform a functional test of each RPS 7 days automatic scram contactor.

SR 3.3.1.1.6 Verify the source range monitor (SRM) and Prior to fully intermediate range monitor (IRM) channels withdrawing overlap. SRMs SR 3.3.1.1.7 ------------------NOTE-------------------

Only required to be met during entry into MODE 2 from MODE 1.

Verify the IRM and APRM channels overlap. 7 days SR 3.3.1.1.8 Perform CHANNEL FUNCTIONAL TEST. 31 days SR 3.3.1.1.9 Calibrate the local power range monitors. 2000 effective full power hours SR 3.3.1.1.10 Perform CHANNEL FUNCTIONAL TEST. 92 days (continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.3.1.1-4 Amendment No. 199/195

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.1.1.11 Calibrate the trip units. 92 days SR 3.3.1.1.12 Perform CHANNEL CALIBRATION. 92 days SR 3.3.1.1.13 Verify Turbine Stop ValveClosure and 92 days Turbine Control Valve Fast Closure, Trip Oil PressureLow Functions are not bypassed when THERMAL POWER is 38.5% RTP.

SR 3.3.1.1.14 ------------------NOTES------------------

1. Neutron detectors are excluded.

2. For Function 2.a, not required to be performed when entering MODE 2 from MODE 1 until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering MODE 2.

3. For Function 2.b, not required for the flow portion of the channels.

Perform CHANNEL CALIBRATION. 184 days SR 3.3.1.1.15 Perform CHANNEL FUNCTIONAL TEST. 24 months (continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.3.1.1-5 Amendment No. 202/198

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.1.1.16 ------------------NOTES------------------

1. Neutron detectors are excluded.

2. For Function 1.a, not required to be performed when entering MODE 2 from MODE 1 until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering MODE 2.

Perform CHANNEL CALIBRATION. 24 months SR 3.3.1.1.17 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months SR 3.3.1.1.18 ------------------NOTES------------------

1. Neutron detectors are excluded.

2. For Function 5 "n" equals 4 channels for the purpose of determining the STAGGERED TEST BASIS Frequency.

Verify the RPS RESPONSE TIME is within 24 months on a limits. STAGGERED TEST BASIS In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.3.1.1-6 Amendment No. 199/195

SRM Instrumentation 3.3.1.2 SURVEILLANCE REQUIREMENTS

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

Refer to Table 3.3.1.2-1 to determine which SRs apply for each applicable MODE or other specified condition.

SURVEILLANCE FREQUENCY SR 3.3.1.2.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.1.2.2 ------------------NOTES------------------

1. Only required to be met during CORE ALTERATIONS.

2. One SRM may be used to satisfy more than one of the following.

Verify an OPERABLE SRM detector is 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months located in:

a. The fueled region;

b. The core quadrant where CORE ALTERATIONS are being performed, when the associated SRM is included in the fueled region; and

c. A core quadrant adjacent to where CORE ALTERATIONS are being performed, when the associated SRM is included in the fueled region.

SR 3.3.1.2.3 Perform CHANNEL CHECK. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months (continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.3.1.2-3 Amendment No. 199/195

SRM Instrumentation 3.3.1.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.1.2.4 ------------------NOTE-------------------

Not required to be met with less than or equal to four fuel assemblies adjacent to the SRM and no other fuel assemblies in the associated core quadrant.

Verify count rate is: 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months during CORE

a. 3.0 cps; or ALTERATIONS

b. 0.7 cps with a signal to noise AND ratio 20:1.

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months SR 3.3.1.2.5 ------------------NOTE-------------------

The determination of signal to noise ratio is not required to be met with less than or equal to four fuel assemblies adjacent to the SRM and no other fuel assemblies in the associated core quadrant.

Perform CHANNEL FUNCTIONAL TEST and 7 days determination of signal to noise ratio.

SR 3.3.1.2.6 ------------------NOTE-------------------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after IRMs on Range 2 or below.

Perform CHANNEL FUNCTIONAL TEST and 31 days determination of signal to noise ratio.

(continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.3.1.2-4 Amendment No. 199/195

SRM Instrumentation 3.3.1.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.1.2.7 ------------------NOTES------------------

1. Neutron detectors are excluded.

2. Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after IRMs on Range 2 or below. In accordance with the

Surveillance Frequency Control Program Perform CHANNEL CALIBRATION. 24 months Quad Cities 1 and 2 3.3.1.2-5 Amendment No. 199/195

OPRM Instrumentation 3.3.1.3 SURVEILLANCE REQUIREMENTS

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

When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the OPRM maintains trip capability.

SURVEILLANCE FREQUENCY SR 3.3.1.3.1 Perform CHANNEL FUNCTIONAL TEST. 184 days SR 3.3.1.3.2 Calibrate the local power range monitors. 2000 effective full power hours SR 3.3.1.3.3 -------------------NOTE--------------------

Neutron detectors are excluded.

Perform CHANNEL CALIBRATION. The setpoints 24 months for the trip function shall be as specified in the COLR.

SR 3.3.1.3.4 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months SR 3.3.1.3.5 Verify OPRM is not bypassed when THERMAL 24 months POWER is 25% RTP and recirculation drive flow is 60% of rated recirculation drive flow.

SR 3.3.1.3.6 -------------------NOTE--------------------

Neutron detectors are excluded.

Verify the RPS RESPONSE TIME is within 24 months on a limits. STAGGERED TEST BASIS In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.3.1.3-3 Amendment No. 227/222

Control Rod Block Instrumentation 3.3.2.1 SURVEILLANCE REQUIREMENTS

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

1. Refer to Table 3.3.2.1-1 to determine which SRs apply for each Control Rod Block Function.

2. When an RBM channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains control rod block capability.

SURVEILLANCE FREQUENCY SR 3.3.2.1.1 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.2.1.2 -----------------NOTE-------------------

Not required to be performed until 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after any control rod is withdrawn at 10% RTP in MODE 2.

Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.2.1.3 ------------------NOTE------------------

Not required to be performed until 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after THERMAL POWER is 10% RTP in MODE 1.

Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.2.1.4 -----------------NOTE-------------------

Neutron detectors are excluded.

Perform CHANNEL CALIBRATION. 92 days (continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.3.2.1-4 Amendment No. 199/195

Control Rod Block Instrumentation 3.3.2.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.2.1.5 -----------------NOTE-------------------

Neutron detectors are excluded.

Verify the RBM is not bypassed when 92 days THERMAL POWER is 30% RTP and when a peripheral control rod is not selected.

SR 3.3.2.1.6 Verify the RWM is not bypassed when 24 months THERMAL POWER is 10% RTP.

In accordance with the SR 3.3.2.1.7 -----------------NOTE-------------------

Surveillance Frequency Not required to be performed until Control Program 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after reactor mode switch is in the shutdown position.

Perform CHANNEL FUNCTIONAL TEST. 24 months SR 3.3.2.1.8 Verify control rod sequences input to Prior to the RWM are in conformance with analyzed declaring RWM rod position sequence. OPERABLE following loading of sequence into RWM SR 3.3.2.1.9 Verify the bypassing and position of Prior to and control rods required to be bypassed in during the RWM by a second licensed operator or movement of other qualified member of the technical control rods staff. bypassed in RWM Quad Cities 1 and 2 3.3.2.1-5 Amendment No. 199/195

Feedwater System and Main Turbine High Water Level Trip Instrumentation 3.3.2.2 SURVEILLANCE REQUIREMENTS

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

When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided Feedwater System and main turbine high water level trip capability is maintained.

SURVEILLANCE FREQUENCY SR 3.3.2.2.1 Perform CHANNEL CHECK. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months SR 3.3.2.2.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.2.2.3 Calibrate the trip unit. 92 days SR 3.3.2.2.4 Perform CHANNEL CALIBRATION. The 24 months Allowable Value shall be 50.34 inches.

SR 3.3.2.2.5 Perform LOGIC SYSTEM FUNCTIONAL TEST, 24 months including breaker and valve actuation.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.3.2.2-3 Amendment No. 230/225

PAM Instrumentation 3.3.3.1 SURVEILLANCE REQUIREMENTS

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

1. These SRs apply to each Function in Table 3.3.3.1-1.

2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the other required channel in the associated Function is OPERABLE.

SURVEILLANCE FREQUENCY SR 3.3.3.1.1 Perform CHANNEL CHECK. 31 days SR 3.3.3.1.2 Perform CHANNEL CALIBRATION. 24 months In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.3.3.1-3 Amendment No. 226/221

ATWS-RPT Instrumentation 3.3.4.1 SURVEILLANCE REQUIREMENTS NOTE When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains ATWS-RPT trip capability.

SURVEILLANCE FREQUENCY SR 3.3.4.1.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.4.1.2 Calibrate the trip units. 92 days SR 3.3.4.1.3 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.4.1.4 Perform CHANNEL CALIBRATION. The 24 months Allowable Values shall be:

a. Reactor Vessel Water LevelLow Low:

-56.3 inches with time delay set to 7.2 seconds and 10.8 seconds; and

b. Reactor Vessel Steam Dome Pressure-High: 1219 psig.

SR 3.3.4.1.5 Perform LOGIC SYSTEM FUNCTIONAL TEST 24 months including breaker actuation.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.3.4.1-3 Amendment No. 213/207

ECCS Instrumentation 3.3.5.1 SURVEILLANCE REQUIREMENTS

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

1. Refer to Table 3.3.5.1-1 to determine which SRs apply for each ECCS Function.

2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed as follows: (a) for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for Functions 3.c, 3.f, and 3.g; and (b) for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for Functions other than 3.c, 3.f, and 3.g provided the associated Function or the redundant Function maintains ECCS initiation capability.

SURVEILLANCE FREQUENCY SR 3.3.5.1.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.5.1.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.5.1.3 Calibrate the trip unit. 92 days SR 3.3.5.1.4 Perform CHANNEL CALIBRATION. 92 days SR 3.3.5.1.5 Perform CHANNEL CALIBRATION. 184 days (continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.3.5.1-8 Amendment No. 204/200

ECCS Instrumentation 3.3.5.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.5.1.6 Perform CHANNEL CALIBRATION. 24 months SR 3.3.5.1.7 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.3.5.1-9 Amendment No. 204/200

RCIC System Instrumentation 3.3.5.2 SURVEILLANCE REQUIREMENTS

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

1. Refer to Table 3.3.5.2-1 to determine which SRs apply for each RCIC Function.

2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed as follows: (a) for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for Functions 2 and 5; and (b) for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for Functions 1, 3, and 4 provided the associated Function maintains RCIC initiation capability.

SURVEILLANCE FREQUENCY SR 3.3.5.2.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.5.2.2 CALIBRATE the trip unit. 92 days SR 3.3.5.2.3 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.5.2.4 Perform CHANNEL CALIBRATION. 24 months SR 3.3.5.2.5 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.3.5.2-3 Amendment No. 204/200

Primary Containment Isolation Instrumentation 3.3.6.1 SURVEILLANCE REQUIREMENTS

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

1. Refer to Table 3.3.6.1-1 to determine which SRs apply for each Primary Containment Isolation Function.

2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains isolation capability.

SURVEILLANCE FREQUENCY SR 3.3.6.1.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.6.1.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.6.1.3 Calibrate the trip unit. 92 days SR 3.3.6.1.4 Perform CHANNEL CALIBRATION. 92 days SR 3.3.6.1.5 Perform CHANNEL FUNCTIONAL TEST. 24 months SR 3.3.6.1.6 Perform CHANNEL CALIBRATION. 24 months SR 3.3.6.1.7 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.3.6.1-4 Amendment No. 199/195

Secondary Containment Isolation Instrumentation 3.3.6.2 SURVEILLANCE REQUIREMENTS

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

1. Refer to Table 3.3.6.2-1 to determine which SRs apply for each Secondary Containment Isolation Function.

2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains isolation capability.

SURVEILLANCE FREQUENCY SR 3.3.6.2.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.6.2.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.6.2.3 Calibrate the trip unit. 92 days SR 3.3.6.2.4 Perform CHANNEL CALIBRATION. 92 days SR 3.3.6.2.5 Perform CHANNEL CALIBRATION. 24 months SR 3.3.6.2.6 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.3.6.2-3 Amendment No. 199/195

Relief Valve Instrumentation 3.3.6.3 SURVEILLANCE REQUIREMENTS

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

Refer to Table 3.3.6.3-1 to determine which SRs apply for each Function.

SURVEILLANCE FREQUENCY SR 3.3.6.3.1 Perform CHANNEL CALIBRATION. 24 months SR 3.3.6.3.2 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.3.6.3-2 Amendment No. 199/195

CREV System Isolation Instrumentation 3.3.7.1 SURVEILLANCE REQUIREMENTS

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

1. Refer to Table 3.3.7.1-1 to determine which SRs apply for each CREV System Isolation Function.

2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains CREV System isolation capability.

SURVEILLANCE FREQUENCY SR 3.3.7.1.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.7.1.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.7.1.3 Calibrate the trip units. 92 days SR 3.3.7.1.4 Perform CHANNEL CALIBRATION. 92 days SR 3.3.7.1.5 Perform CHANNEL CALIBRATION. 24 months SR 3.3.7.1.6 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.3.7.1-3 Amendment No. 199/195

Mechanical Vacuum Pump Trip Instrumentation 3.3.7.2 SURVEILLANCE REQUIREMENTS

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

When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided mechanical vacuum pump trip capability is maintained.

SURVEILLANCE FREQUENCY SR 3.3.7.2.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.7.2.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.7.2.3 -------------------NOTE------------------

Radiation detectors are excluded.

Perform CHANNEL CALIBRATION. 92 days SR 3.3.7.2.4 Perform CHANNEL CALIBRATION. The 24 months Allowable Value shall be 7700 mR/hr.

SR 3.3.7.2.5 Perform LOGIC SYSTEM FUNCTIONAL TEST 24 months including mechanical vacuum pump breaker actuation.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.3.7.2-3 Amendment No. 199/195

LOP Instrumentation 3.3.8.1 SURVEILLANCE REQUIREMENTS

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

1. Refer to Table 3.3.8.1-1 to determine which SRs apply for each LOP Function.

2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months provided the associated Function maintains LOP initiation capability.

SURVEILLANCE FREQUENCY SR 3.3.8.1.1 Perform CHANNEL FUNCTIONAL TEST. 18 months SR 3.3.8.1.2 Perform CHANNEL CALIBRATION. 18 months SR 3.3.8.1.3 Perform CHANNEL FUNCTIONAL TEST. 24 months SR 3.3.8.1.4 Perform CHANNEL CALIBRATION. 24 months SR 3.3.8.1.5 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.3.8.1-2 Amendment No. 199/195

RPS Electric Power Monitoring 3.3.8.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and D.1 Initiate action to Immediately associated Completion fully insert all Time of Condition A insertable control or B not met in MODE 5 rods in core cells with any control rod containing one or withdrawn from a core more fuel assemblies.

cell containing one or more fuel assemblies.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.8.2.1 ------------------NOTE-------------------

Only required to be performed prior to entering MODE 2 from MODE 3 or 4, when in MODE 4 for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

Perform CHANNEL FUNCTIONAL TEST. 184 days SR 3.3.8.2.2 Perform CHANNEL CALIBRATION. The 24 months Allowable Values shall be:

a. Overvoltage 129.4 V, with time delay set to 3.59 seconds.

b. Undervoltage 105.6 V, with time delay set to 3.59 seconds.

c. Underfrequency 55.6 Hz, with time delay set to 3.59 seconds.

SR 3.3.8.2.3 Perform a system functional test. 24 months In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.3.8.2-2 Amendment No. 199/195

Recirculation Loops Operating 3.4.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. Recirculation loop B.1 Declare the 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months flow mismatch not recirculation loop within limits. with lower flow to be "not in operation."

C. Requirements of the C.1 Satisfy the 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months LCO not met for requirements of the reasons other than LCO.

Condition A or B.

D. Required Action and D.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition C not met.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.1.1 --------------------NOTE-------------------

Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after both recirculation loops are in operation.

Verify jet pump loop flow mismatch with 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months both recirculation loops in operation is: In accordance with the Surveillance Frequency

a. 10% of rated core flow when Control Program operating at < 70% of rated core flow; and

b. 5% of rated core flow when operating at 70% of rated core flow.

Quad Cities 1 and 2 3.4.1-2 Amendment No. 199/195

Jet Pumps 3.4.2 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.2 Jet Pumps LCO 3.4.2 All jet pumps shall be OPERABLE.

APPLICABILITY: MODES 1 and 2.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more jet pumps A.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months inoperable.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.2.1 -------------------NOTES-------------------

1. Not required to be performed until 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after associated recirculation loop is in operation.

2. Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after > 25% RTP.

Verify at least one of the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months criteria (a or b) is satisfied for each In accordance with the operating recirculation loop: Surveillance Frequency Control Program

a. Recirculation pump flow to speed ratio differs by 10% from established patterns.

b. Each jet pump flow differs by 10%

from established patterns.

Quad Cities 1 and 2 3.4.2-1 Amendment No. 199/195

Safety and Relief Valves 3.4.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.3.1 Verify the safety function lift setpoints In accordance of the safety valves are as follows: with the Inservice Number of Setpoint Testing Program Safety Valves (psig) 1 1135 +/- 34.1 2 1240 +/- 37.2 2 1250 +/- 37.5 4 1260 +/- 37.8 Following testing, lift settings shall be within +/- 1%.

SR 3.4.3.2 Verify each relief valve actuator strokes 24 months when manually actuated.

SR 3.4.3.3 -------------------NOTE--------------------

Valve actuation may be excluded.

Verify each relief valve actuates on an 24 months actual or simulated automatic initiation signal.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.4.3-2 Amendment No. 235/230

RCS Operational LEAKAGE 3.4.4 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.2 Verify source of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months unidentified LEAKAGE increase is not intergranular stress corrosion cracking susceptible material.

C. Required Action and C.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A AND or B not met.

C.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months OR Pressure boundary LEAKAGE exists.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.4.1 Verify RCS unidentified and total LEAKAGE 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and unidentified LEAKAGE increase are In accordance with the within limits. Surveillance Frequency Control Program Quad Cities 1 and 2 3.4.4-2 Amendment No. 199/195

RCS Leakage Detection Instrumentation 3.4.5 SURVEILLANCE REQUIREMENTS

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

When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the other required leakage detection instrumentation is OPERABLE.

SURVEILLANCE FREQUENCY SR 3.4.5.1 Perform a CHANNEL CHECK of the the primary 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months containment atmospheric particulate monitoring system.

SR 3.4.5.2 Perform a CHANNEL FUNCTIONAL TEST of 31 days required leakage detection instrumentation.

SR 3.4.5.3 Perform a CHANNEL CALIBRATION of required 24 months leakage detection instrumentation.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.4.5-3 Amendment No. 199/195

RCS Specific Activity 3.4.6 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.2.2.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months AND B.2.2.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.6.1 -------------------NOTE--------------------

Only required to be performed in MODE 1. In accordance with the

Surveillance Frequency Control Program Verify reactor coolant DOSE EQUIVALENT 7 days I-131 specific activity is 0.2 Ci/gm.

Quad Cities 1 and 2 3.4.6-2 Amendment No. 199/195

RHR Shutdown Cooling SystemHot Shutdown 3.4.7 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.7.1 -------------------NOTE--------------------

Not required to be met until 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months after reactor steam dome pressure is less than the RHR cut-in permissive pressure.

Verify each RHR shutdown cooling subsystem 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months manual and power operated valve in the flow In accordance with the path, that is not locked, sealed or Surveillance Frequency otherwise secured in position, is in the Control Program correct position or can be aligned to the correct position.

Quad Cities 1 and 2 3.4.7-3 Amendment No. 199/195

RHR Shutdown Cooling SystemCold Shutdown 3.4.8 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2 ---------NOTE--------

Only applicable if both RHR shutdown cooling subsystems are inoperable.

Verify reactor 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months coolant circulating by an alternate AND method.

Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND A.3 ---------NOTE--------

Only applicable if both RHR shutdown cooling subsystems are inoperable.

Monitor reactor Once per hour coolant temperature and pressure.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.8.1 Verify each RHR shutdown cooling subsystem 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months manual and power operated valve in the flow In accordance with the path, that is not locked, sealed or Surveillance Frequency otherwise secured in position, is in the Control Program correct position or can be aligned to the correct position.

Quad Cities 1 and 2 3.4.8-2 Amendment No. 199/195

RCS P/T Limits 3.4.9 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.9.1 -------------------NOTE--------------------

Only required to be performed during RCS heatup and cooldown operations and RCS inservice leak and hydrostatic testing.

Verify: 30 minutes In accordance with the

a. RCS pressure and RCS temperature are Surveillance Frequency within the applicable limits specified Control Program in Figures 3.4.9-1, 3.4.9-2, and 3.4.9-3;

b. RCS heatup and cooldown rates are

100F in any 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months period; and

c. RCS temperature change during inservice leak and hydrostatic testing is 20F in any 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months period when the RCS pressure and RCS temperature are being maintained within the limits of Figure 3.4.9-1.

SR 3.4.9.2 Verify RCS pressure and RCS temperature are Once within within the applicable criticality limits 15 minutes specified in Figure 3.4.9-3. prior to control rod withdrawal for the purpose of achieving criticality (continued)

Quad Cities 1 and 2 3.4.9-3 Amendment No. 199/195

RCS P/T Limits 3.4.9 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.9.3 --------------------NOTE-------------------

Only required to be met in MODES 1, 2, 3, and 4 during recirculation pump startup.

Verify the difference between the bottom Once within head coolant temperature and the reactor 15 minutes pressure vessel (RPV) coolant temperature prior to each is 145F. startup of a recirculation pump SR 3.4.9.4 -------------------NOTE--------------------

Only required to be met in MODES 1, 2, 3, and 4 during recirculation pump startup.

Verify the difference between the reactor Once within coolant temperature in the recirculation 15 minutes loop to be started and the RPV coolant prior to each temperature is 50F. startup of a recirculation pump SR 3.4.9.5 -------------------NOTE--------------------

Only required to be performed when tensioning the reactor vessel head bolting studs. In accordance with the

Surveillance Frequency Control Program Verify reactor vessel flange and head 30 minutes flange temperatures are 83F.

(continued)

Quad Cities 1 and 2 3.4.9-4 Amendment No. 199/195

RCS P/T Limits 3.4.9 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.9.6 -------------------NOTE--------------------

Not required to be performed until 30 minutes after RCS temperature 93F in MODE 4.

Verify reactor vessel flange and head 30 minutes flange temperatures are 83F.

SR 3.4.9.7 -------------------NOTE--------------------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after RCS temperature 113F in MODE 4.

Verify reactor vessel flange and head 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months flange temperatures are 83F.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.4.9-5 Amendment No. 199/195

Reactor Steam Dome Pressure 3.4.10 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.10 Reactor Steam Dome Pressure LCO 3.4.10 The reactor steam dome pressure shall be 1005 psig.

APPLICABILITY: MODES 1 and 2.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Reactor steam dome A.1 Restore reactor steam 15 minutes pressure not within dome pressure to limit. within limit.

B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.10.1 Verify reactor steam dome pressure is 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 1005 psig.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.4.10-1 Amendment No. 199/195

ECCSOperating 3.5.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.1.1 Verify, for each ECCS injection/spray 31 days subsystem, the piping is filled with water from the pump discharge valve to the injection valve.

SR 3.5.1.2 -------------------NOTE--------------------

Low pressure coolant injection (LPCI) subsystems may be considered OPERABLE during alignment and operation for decay heat removal with reactor steam dome pressure less than the Residual Heat Removal (RHR) cut-in permissive pressure in MODE 3, if capable of being manually realigned and not otherwise inoperable.

Verify each ECCS injection/spray subsystem 31 days manual, power operated, and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position.

SR 3.5.1.3 Verify correct breaker alignment to the 31 days LPCI swing bus.

SR 3.5.1.4 Verify each recirculation pump discharge In accordance valve cycles through one complete cycle of with the full travel or is de-energized in the Inservice closed position. Testing Program (continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.5.1-4 Amendment No. 199/195

ECCSOperating 3.5.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.1.5 Verify the following ECCS pumps develop the In accordance specified flow rate against a test line with the pressure corresponding to the specified Inservice reactor pressure. Testing Program TEST LINE PRESSURE NO. CORRESPONDING OF TO A REACTOR SYSTEM FLOW RATE PUMPS PRESSURE OF Core Spray 4500 gpm 1 90 psig LPCI 9000 gpm 2 20 psig SR 3.5.1.6 -------------------NOTE--------------------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reactor steam pressure and flow are adequate to perform the test.

Verify, with reactor pressure 1005 and In accordance 920 psig, the HPCI pump can develop a with the flow rate 5000 gpm against a system head Inservice corresponding to reactor pressure. Testing Program SR 3.5.1.7 -------------------NOTE--------------------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reactor steam pressure and flow are adequate to perform the test.

Verify, with reactor pressure 180 psig, 24 months the HPCI pump can develop a flow rate In accordance with the 5000 gpm against a system head Surveillance Frequency corresponding to reactor pressure. Control Program (continued)

Quad Cities 1 and 2 3.5.1-5 Amendment No. 199/195

ECCSOperating 3.5.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.1.8 -------------------NOTE--------------------

Vessel injection/spray may be excluded.

Verify each ECCS injection/spray subsystem 24 months actuates on an actual or simulated automatic initiation signal.

SR 3.5.1.9 -------------------NOTE--------------------

Valve actuation may be excluded.

Verify the ADS actuates on an actual or 24 months simulated automatic initiation signal.

SR 3.5.1.10 Verify each ADS valve actuator strokes when 24 months manually actuated.

SR 3.5.1.11 Verify automatic transfer capability of the 24 months LPCI swing bus power supply from the normal source to the backup source.

SR 3.5.1.12 Verify ADS pneumatic supply header pressure 31 days is > 80 psig.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.5.1-6 Amendment No. 222/217

ECCSShutdown 3.5.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.2.1 Verify, for each required ECCS injection/ 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months spray subsystem, the:

a. Suppression pool water level is 8.5 ft; or

b. -----------------NOTE-----------------

Only one required ECCS injection/spray subsystem may take credit for this option during OPDRVs.

Contaminated condensate storage tank(s) water volume is 140,000 available gallons.

SR 3.5.2.2 Verify, for each required ECCS injection/ 31 days spray subsystem, the piping is filled with water from the pump discharge valve to the injection valve.

SR 3.5.2.3 --------------------NOTE-------------------

One LPCI subsystem may be considered OPERABLE during alignment and operation for decay heat removal if capable of being manually realigned and not otherwise inoperable.

Verify each required ECCS injection/spray 31 days subsystem manual, power operated, and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position.

(continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.5.2-3 Amendment No. 199/195

ECCSShutdown 3.5.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.2.4 Verify each required ECCS pump develops the In accordance specified flow rate against a test line with the pressure corresponding to the specified Inservice reactor pressure. Testing Program TEST LINE PRESSURE NO. CORRESPONDING OF TO A REACTOR SYSTEM FLOW RATE PUMPS PRESSURE OF CS 4500 gpm 1 90 psig LPCI 4500 gpm 1 20 psig SR 3.5.2.5 -------------------NOTE--------------------

Vessel injection/spray may be excluded.

Verify each required ECCS injection/spray 24 months subsystem actuates on an actual or In accordance with the simulated automatic initiation signal. Surveillance Frequency Control Program Quad Cities 1 and 2 3.5.2-4 Amendment No. 199/195

RCIC System 3.5.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.3.1 Verify the RCIC System piping is filled 31 days with water from the pump discharge valve to the injection valve.

SR 3.5.3.2 Verify each RCIC System manual, power 31 days operated, and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position.

SR 3.5.3.3 --------------------NOTE-------------------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reactor steam pressure and flow are adequate to perform the test.

Verify, with reactor pressure 1005 psig 92 days and 920 psig, the RCIC pump can develop a flow rate 400 gpm against a system head corresponding to reactor pressure.

SR 3.5.3.4 --------------------NOTE-------------------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reactor steam pressure and flow are adequate to perform the test.

Verify, with reactor pressure 180 psig, 24 months the RCIC pump can develop a flow rate 400 gpm against a system head corresponding to reactor pressure.

(continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.5.3-2 Amendment No. 199/195

RCIC System 3.5.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.3.5 --------------------NOTE-------------------

Vessel injection may be excluded.

Verify the RCIC System actuates on an 24 months actual or simulated automatic initiation In accordance with the signal. Surveillance Frequency Control Program Quad Cities 1 and 2 3.5.3-3 Amendment No. 199/195

Primary Containment 3.6.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.1.1 Perform required visual examinations and In accordance leakage rate testing except for primary with the containment air lock testing, in Primary accordance with the Primary Containment Containment Leakage Rate Testing Program. Leakage Rate Testing Program SR 3.6.1.1.2 Verify drywell-to-suppression chamber 24 months bypass leakage is 2% of the acceptable A/ k design value of 0.18 ft2 at an AND initial differential pressure of 1.0 psid. ------NOTE-----

Only required after two consecutive tests fail and continues until two consecutive tests pass 12 months In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.6.1.1-2 Amendment No. 199/195

Primary Containment Air Lock 3.6.1.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and D.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met. AND D.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.2.1 ------------------NOTES------------------

1. An inoperable air lock door does not invalidate the previous successful performance of the overall air lock leakage test.

2. Results shall be evaluated against acceptance criteria applicable to SR 3.6.1.1.1.

Perform required primary containment air In accordance lock leakage rate testing in accordance with the with the Primary Containment Leakage Rate Primary Testing Program. Containment Leakage Rate Testing Program SR 3.6.1.2.2 Verify only one door in the primary 24 months containment air lock can be opened at a In accordance with the time. Surveillance Frequency Control Program Quad Cities 1 and 2 3.6.1.2-4 Amendment No. 199/195

PCIVs 3.6.1.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME F. Required Action and F.1 Initiate action to Immediately associated Completion suspend operations Time of Condition A, with a potential for B, C, or D not met for draining the reactor PCIV(s) required to be vessel (OPDRVs).

OPERABLE during MODE 4 or 5. OR F.2 Initiate action to Immediately restore valve(s) to OPERABLE status.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.3.1 ------------------NOTE-------------------

Not required to be met when the 18 inch primary containment vent and purge valves are open for inerting, de-inerting, pressure control, ALARA or air quality considerations for personnel entry, or Surveillances that require the valves to be open, provided the drywell vent and purge valves and their associated suppression chamber vent and purge valves are not open simultaneously.

Verify each 18 inch primary containment 31 days vent and purge valve, except for the In accordance with the torus purge valve, is closed. Surveillance Frequency Control Program (continued)

Quad Cities 1 and 2 3.6.1.3-5 Amendment No. 199/195

PCIVs 3.6.1.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.3.2 ------------------NOTES------------------

1. Valves and blind flanges in high radiation areas may be verified by use of administrative means.

2. Not required to be met for PCIVs that are open under administrative controls.

Verify each primary containment isolation 31 days manual valve and blind flange that is In accordance with the located outside primary containment and Surveillance Frequency not locked, sealed, or otherwise secured Control Program and is required to be closed during accident conditions is closed.

SR 3.6.1.3.3 ------------------NOTES------------------

1. Valves and blind flanges in high radiation areas may be verified by use of administrative means.

2. Not required to be met for PCIVs that are open under administrative controls.

Verify each primary containment manual Prior to isolation valve and blind flange that is entering MODE 2 located inside primary containment and or 3 from not locked sealed, or otherwise secured MODE 4 if and is required to be closed during primary accident conditions is closed. containment was de-inerted while in MODE 4, if not performed within the previous 92 days (continued)

Quad Cities 1 and 2 3.6.1.3-6 Amendment No. 199/195

PCIVs 3.6.1.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.3.4 Verify continuity of the traversing 31 days incore probe (TIP) shear isolation valve explosive charge.

SR 3.6.1.3.5 Verify the isolation time of each power In accordance operated, automatic PCIV, except for with the MSIVs, is within limits. Inservice Testing Program SR 3.6.1.3.6 Verify the isolation time of each MSIV is In accordance 3 seconds and 5 seconds. with the Inservice Testing Program SR 3.6.1.3.7 Verify each automatic PCIV actuates to 24 months the isolation position on an actual or simulated isolation signal.

SR 3.6.1.3.8 Verify a representative sample of reactor 24 months instrumentation line EFCVs actuate to the isolation position on an actual or simulated instrument line break signal.

SR 3.6.1.3.9 Remove and test the explosive squib from 24 months on a each shear isolation valve of the TIP STAGGERED TEST System. BASIS (continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.6.1.3-7 Amendment No. 218/212

Drywell Pressure 3.6.1.4 3.6 CONTAINMENT SYSTEMS 3.6.1.4 Drywell Pressure LCO 3.6.1.4 Drywell pressure shall be 1.5 psig.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Drywell pressure not A.1 Restore drywell 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months within limit. pressure to within limit.

B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met. AND B.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.4.1 Verify drywell pressure is within limit. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.6.1.4-1 Amendment No. 199/195

Drywell Air Temperature 3.6.1.5 3.6 CONTAINMENT SYSTEMS 3.6.1.5 Drywell Air Temperature LCO 3.6.1.5 Drywell average air temperature shall be 150°F.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Drywell average air A.1 Restore drywell 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months temperature not within average air limit. temperature to within limit.

B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met. AND B.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.5.1 Verify drywell average air temperature is 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months within limit.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.6.1.5-1 Amendment No. 199/195

Low Set Relief Valves 3.6.1.6 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.6.1 Verify each low set relief valve actuator 24 months strokes when manually actuated.

SR 3.6.1.6.2 ------------------NOTE-------------------

Valve actuation may be excluded.

Verify each low set relief valve actuates 24 months on an actual or simulated automatic initiation signal.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.6.1.6-2 Amendment No. 222/217

Reactor Building-to-Suppression Chamber Vacuum Breakers 3.6.1.7 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and --------------NOTE-----------

Associated Completion LCO 3.0.4.a is not applicable Time of Condition C not when entering MODE 3.

met. -----------------------------

D.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months E. Two lines with one or E.1 Restore all vacuum 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months more reactor building- breakers in one line to-suppression chamber to OPERABLE status.

vacuum breakers inoperable for opening.

F. Required Action and F.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Associated Completion Time of Conditions A, AND B or E not met.

F.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.7.1 ------------------NOTES------------------

1. Not required to be met for vacuum breakers that are open during Surveillances.

2. Not required to be met for vacuum In accordance with the breakers open when performing their Surveillance Frequency intended function. Control Program Verify each vacuum breaker is closed. 14 days SR 3.6.1.7.2 Perform a functional test of each vacuum 92 days breaker.

(continued)

Quad Cities 1 and 2 3.6.1.7-2 Amendment No. 245/240

Reactor Building-to-Suppression Chamber Vacuum Breakers 3.6.1.7 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.7.3 Verify the opening setpoint of each 24 months vacuum breaker is 0.5 psid.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.6.1.7-3 Amendment No. 199/195

Suppression Chamber-to-Drywell Vacuum Breakers 3.6.1.8 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.8.1 ------------------NOTES------------------

1. Not required to be met for vacuum breakers that are open during Surveillances.

2. Not required to be met for vacuum breakers open when performing their intended function.

Verify each vacuum breaker is closed. 14 days SR 3.6.1.8.2 Perform a functional test of each 31 days required vacuum breaker.

AND Within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after any discharge of steam to the suppression chamber from the relief valves SR 3.6.1.8.3 Verify the opening setpoint of each 24 months required vacuum breaker is 0.5 psid.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.6.1.8-2 Amendment No. 199/195

Suppression Pool Average Temperature 3.6.2.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.2.1.1 Verify suppression pool average 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months temperature is within the applicable limits. AND 5 minutes when performing testing that adds heat to the suppression pool In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.6.2.1-3 Amendment No. 199/195

Suppression Pool Water Level 3.6.2.2 3.6 CONTAINMENT SYSTEMS 3.6.2.2 Suppression Pool Water Level LCO 3.6.2.2 Suppression pool water level shall be 14 ft 1 inch and 14 ft 5 inches.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Suppression pool water A.1 Restore suppression 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months level not within pool water level to limits. within limits.

B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met. AND B.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.2.2.1 Verify suppression pool water level is 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months within limits.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.6.2.2-1 Amendment No. 199/195

RHR Suppression Pool Cooling 3.6.2.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.2.3.1 Verify each RHR suppression pool cooling 31 days subsystem manual and power operated valve In accordance with the in the flow path that is not locked, Surveillance Frequency sealed, or otherwise secured in position, Control Program is in the correct position or can be aligned to the correct position.

SR 3.6.2.3.2 Verify each required RHR pump develops a In accordance flow rate 5000 gpm through the with the associated heat exchanger while operating Inservice in the suppression pool cooling mode. Testing Program Quad Cities 1 and 2 3.6.2.3-2 Amendment No. 199/195

RHR Suppression Pool Spray 3.6.2.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.2.4.1 Verify each RHR suppression pool spray 31 days subsystem manual and power operated valve in the flow path that is not locked, sealed, or otherwise secured in position, is in the correct position or can be aligned to the correct position.

SR 3.6.2.4.2 Verify each suppression pool spray nozzle 10 years is unobstructed.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.6.2.4-2 Amendment No. 199/195

Drywell-to-Suppression Chamber Differential Pressure 3.6.2.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.2.5.1 Verify drywell-to-suppression chamber 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months differential pressure is within limit.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.6.2.5-2 Amendment No. 199/195

Primary Containment Oxygen Concentration 3.6.3.1 3.6 CONTAINMENT SYSTEMS 3.6.3.1 Primary Containment Oxygen Concentration LCO 3.6.3.1 The primary containment oxygen concentration shall be

< 4.0 volume percent.

APPLICABILITY: MODE 1 during the time period:

a. From 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after THERMAL POWER is > 15% RTP following startup, to

b. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months prior to reducing THERMAL POWER to < 15% RTP prior to the next scheduled reactor shutdown.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Primary containment A.1 Restore oxygen 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months oxygen concentration concentration to not within limit. within limit.

B. Required Action and B.1 Reduce THERMAL POWER 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months associated Completion to 15% RTP.

Time not met.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.3.1.1 Verify primary containment oxygen 7 days concentration is within limits.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.6.3.1-1 Amendment No. 199/195

Secondary Containment 3.6.4.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.1.1 Verify secondary containment vacuum is 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 0.10 inch of vacuum water gauge.

SR 3.6.4.1.2 Verify one secondary containment access 31 days door in each access opening is closed.

SR 3.6.4.1.3 Verify the secondary containment can be 24 months on a maintained 0.25 inch of vacuum water STAGGERED TEST gauge for 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months using one SGT subsystem BASIS for each at a flow rate 4000 cfm. SGT subsystem SR 3.6.4.1.4 Verify all secondary containment 24 months equipment hatches are closed and sealed.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.6.4.1-2 Amendment No. 233/229

SCIVs 3.6.4.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.2.1 ------------------NOTES------------------

1. Valves and blind flanges in high radiation areas may be verified by use of administrative means.

2. Not required to be met for SCIVs that are open under administrative controls.

Verify each secondary containment 31 days isolation manual valve and blind flange that is not locked, sealed, or otherwise secured and is required to be closed during accident conditions is closed.

SR 3.6.4.2.2 Verify the isolation time of each power 92 days operated, automatic SCIV is within limits.

SR 3.6.4.2.3 Verify each automatic SCIV actuates to 24 months the isolation position on an actual or simulated actuation signal.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.6.4.2-4 Amendment No. 199/195

SGT System 3.6.4.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.3.1 Operate each SGT subsystem for 31 days 10 continuous hours with heaters operating.

SR 3.6.4.3.2 Perform required SGT filter testing in In accordance accordance with the Ventilation Filter with the VFTP Testing Program (VFTP).

SR 3.6.4.3.3 Verify each SGT subsystem actuates on an 24 months actual or simulated initiation signal.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.6.4.3-3 Amendment No. 233/229

RHRSW System 3.7.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and --------------NOTE-----------

associated Completion LCO 3.0.4.a is not applicable Time of Conditions A, when entering MODE 3.

B, or C not met. -----------------------------

D.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months E. Both RHRSW subsystems E.1 --------NOTE---------

inoperable for reasons Enter applicable other than Conditions and Condition B. Required Actions of LCO 3.4.7 for RHR shutdown cooling subsystems made inoperable by RHRSW System.

Restore one RHRSW 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months subsystem to OPERABLE status.

F. Required Action and F.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition E AND not met. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months F.2 Be in MODE 4.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.1.1 Verify each RHRSW manual and power operated 31 days valve in the flow path, that is not locked, sealed, or otherwise secured in position, In accordance with the is in the correct position or can be Surveillance Frequency aligned to the correct position. Control Program Quad Cities 1 and 2 3.7.1-2 Amendment No. 245/240

DGCW System 3.7.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.2.1 Verify each DGCW subsystem manual valve in 31 days the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position.

SR 3.7.2.2 Verify each DGCW pump starts automatically 24 months on an actual or simulated initiation signal.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.7.2-2 Amendment No. 199/195

UHS 3.7.3 3.7 PLANT SYSTEMS 3.7.3 Ultimate Heat Sink (UHS)

LCO 3.7.3 The UHS shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. UHS inoperable. A.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months AND A.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.3.1 Verify the water level in the intake bay is 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 568 ft mean sea level.

SR 3.7.3.2 Verify the average water temperature of UHS 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is 95°F.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.7.3-1 Amendment No. 199/195

CREV System 3.7.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.4.1 Operate the CREV System for 10 continuous 31 days hours with the heaters operating.

SR 3.7.4.2 Perform required CREV filter testing in In accordance accordance with the Ventilation Filter with the VFTP Testing Program (VFTP).

SR 3.7.4.3 Verify the CREV System isolation dampers 24 months close on an actual or simulated initiation signal.

SR 3.7.4.4 Perform required CRE unfiltered air In accordance inleakage testing in accordance with the with the Control Room Envelope Habitability Program. Control Room Envelope Habitability Program In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.7.4-3 Amendment No. 238/233

Control Room Emergency Ventilation AC System 3.7.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.5.1 Verify the Control Room Emergency 24 months Ventilation AC System has the capability to In accordance with the remove the assumed heat load. Surveillance Frequency Control Program Quad Cities 1 and 2 3.7.5-2 Amendment No. 233/229

Main Condenser Offgas 3.7.6 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.6.1 -------------------NOTE--------------------

Not required to be performed until 31 days after any main steam line not isolated and SJAE in operation.

Verify the gross gamma activity rate of the 31 days noble gases is 251,100 Ci/second after decay of 30 minutes. AND Once within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after a 50% increase in the nominal steady state fission gas release after factoring out increases due to changes in THERMAL POWER level In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.7.6-2 Amendment No. 199/195

Main Turbine Bypass System 3.7.7 3.7 PLANT SYSTEMS 3.7.7 The Main Turbine Bypass System LCO 3.7.7 The Main Turbine Bypass System shall be OPERABLE.

OR LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)," limits for an inoperable Main Turbine Bypass System, as specified in the COLR, are made applicable.

APPLICABILITY: THERMAL POWER 25% RTP.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Requirements of the A.1 Satisfy the 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months LCO not met. requirements of the LCO.

B. Required Action and B.1 Reduce THERMAL POWER 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months associated Completion to < 25% RTP.

Time not met.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.7.1 Verify one complete cycle of each main 92 days turbine bypass valve.

(continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.7.7-1 Amendment No. 199/195

Main Turbine Bypass System 3.7.7 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.7.2 Perform a system functional test. 24 months SR 3.7.7.3 Verify the TURBINE BYPASS SYSTEM RESPONSE 24 months TIME is within limits.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.7.7-2 Amendment No. 199/195

Spent Fuel Storage Pool Water Level 3.7.8 3.7 PLANT SYSTEMS 3.7.8 Spent Fuel Storage Pool Water Level LCO 3.7.8 The spent fuel storage pool water level shall be 19 ft over the top of irradiated fuel assemblies seated in the spent fuel storage pool racks.

APPLICABILITY: During movement of irradiated fuel assemblies in the spent fuel storage pool, During movement of new fuel assemblies in the spent fuel storage pool with irradiated fuel assemblies seated in the spent fuel storage pool.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Spent fuel storage A.1 --------NOTE---------

pool water level not LCO 3.0.3 is not within limit. applicable.

Suspend movement of Immediately fuel assemblies in the spent fuel storage pool.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.8.1 Verify the spent fuel storage pool water 7 days level is 19 ft over the top of irradiated In accordance with the fuel assemblies seated in the spent fuel Surveillance Frequency storage pool racks. Control Program Quad Cities 1 and 2 3.7.8-1 Amendment No. 199/195

SSMP System 3.7.9 3.7 PLANT SYSTEMS 3.7.9 Safe Shutdown Makeup Pump (SSMP) System LCO 3.7.9 The SSMP System shall be OPERABLE.

APPLICABILITY: MODE 1, MODES 2 and 3 with reactor steam dome pressure > 150 psig.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. SSMP System A.1 Restore SSMP System 14 days inoperable. to OPERABLE status.

B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met. AND B.2 Reduce reactor steam 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months dome pressure to 150 psig.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.9.1 Verify each SSMP System manual, power 31 days operated, and automatic valve in the flow In accordance with the path, that is not locked, sealed, or Surveillance Frequency otherwise secured in position, is in the Control Program correct position.

(continued)

Quad Cities 1 and 2 3.7.9-1 Amendment No. 199/195

SSMP System 3.7.9 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.9.2 Verify SSMP System pump develops a flow 92 days rate 400 gpm against a system head In accordance with the corresponding to reactor pressure Surveillance Frequency

> 1120 psig. Control Program Quad Cities 1 and 2 3.7.9-2 Amendment No. 199/195

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS

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

1. SR 3.8.1.1 through SR 3.8.1.20 are applicable only to the given unit's AC electrical power sources.

2. SR 3.8.1.21 is applicable to the opposite unit's AC electrical power sources.

SURVEILLANCE FREQUENCY SR 3.8.1.1 Verify correct breaker alignment and 7 days indicated power availability for each required offsite circuit.

SR 3.8.1.2 -------------------NOTES-------------------

1. All DG starts may be preceded by an engine prelube period and followed by a warmup period prior to loading.

2. A modified DG start involving idling and gradual acceleration to synchronous speed may be used for this SR as recommended by the manufacturer.

When modified start procedures are not used, the time, voltage, and frequency tolerances of SR 3.8.1.8 must be met.

3. A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units.

Verify each DG starts from standby 31 days conditions and achieves steady state voltage 3952 V and 4368 V and frequency 58.8 Hz and 61.2 Hz.

(continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.8.1-6 Amendment No. 199/195

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.3 -------------------NOTES-------------------

1. DG loadings may include gradual loading as recommended by the manufacturer.

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

3. This Surveillance shall be conducted on only one DG at a time.

4. This SR shall be preceded by and immediately follow, without shutdown, a successful performance of SR 3.8.1.2 or SR 3.8.1.8.

5. A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units.

Verify each DG is synchronized and loaded 31 days and operates for 60 minutes at a load 2340 kW and 2600 kW.

SR 3.8.1.4 Verify each day tank contains 205 gal of 31 days fuel oil and each bulk fuel storage tank contains 10,000 gal of fuel oil.

SR 3.8.1.5 Remove accumulated water from each day 31 days tank.

SR 3.8.1.6 Verify each fuel oil transfer pump operates 31 days to automatically transfer fuel oil from the storage tank to the day tank.

(continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.8.1-7 Amendment No. 199/195

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.7 Check for and remove accumulated water from 92 days each bulk storage tank.

SR 3.8.1.8 -------------------NOTES-------------------

1. All DG starts may be preceded by an engine prelube period.

2. A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units.

Verify each DG starts from standby 184 days condition and achieves:

a. In 13 seconds, voltage 3952 V and frequency 58.8 Hz; and

b. Steady state voltage 3952 V and 4368 V and frequency 58.8 Hz and 61.2 Hz.

SR 3.8.1.9 Verify manual transfer of unit power supply 24 months from the normal offsite circuit to the alternate offsite circuit.

(continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.8.1-8 Amendment No. 206/202

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.10 -------------------NOTE--------------------

A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units.

Verify each DG rejects a load greater than 24 months or equal to its associated single largest post-accident load, and:

a. Following load rejection, the frequency is 66.73 Hz;

b. Within 3 seconds following load rejection, the voltage is 3952 V and 4368 V; and

c. Within 4 seconds following load rejection, the frequency is 58.8 Hz and 61.2 Hz.

SR 3.8.1.11 ------------------NOTES--------------------

1. A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units.

2. Momentary transients outside the voltage limit do not invalidate this test.

Verify each DG does not trip and voltage is 24 months maintained 5000 V during and following a load rejection of 2340 kW and 2600 kW.

(continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.8.1-9 Amendment No. 199/195

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.12 -------------------NOTE--------------------

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

Verify on an actual or simulated loss of 24 months offsite power signal: In accordance with the Surveillance Frequency

a. De-energization of emergency buses; Control Program

b. Load shedding from emergency buses; and

c. DG auto-starts from standby condition and:

1. energizes permanently connected loads in 13 seconds,

2. maintains steady state voltage 3952 V and 4368 V,

3. maintains steady state frequency 58.8 Hz and 61.2 Hz, and

4. supplies permanently connected loads for 5 minutes.

(continued)

Quad Cities 1 and 2 3.8.1-10 Amendment No. 206/202

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.13 -------------------NOTE--------------------

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

Verify on an actual or simulated Emergency 24 months Core Cooling System (ECCS) initiation signal each DG auto-starts from standby condition and:

a. In 13 seconds after auto-start, achieves voltage 3952 V and frequency 58.8 Hz;

b. Achieves steady state voltage 3952 V and 4368 V and frequency 58.8 Hz and 61.2 Hz; and

c. Operates for 5 minutes.

SR 3.8.1.14 Verify each DG's automatic trips are 24 months bypassed on actual or simulated loss of voltage signal on the emergency bus concurrent with an actual or simulated ECCS initiation signal except:

a. Engine overspeed; and

b. Generator differential current.

(continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.8.1-11 Amendment No. 206/202

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.15 -------------------NOTES-------------------

1. Momentary transients outside the load range and power factor limit do not invalidate this test.

2. If grid conditions do not permit, the power factor limit is not required to be met. Under this condition, the power factor shall be maintained as close to the limit as practicable.

3. A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units.

Verify each DG operating within the power 24 months factor limit operates for 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months s: In accordance with the Surveillance Frequency

a. For 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months loaded 2730 kW and Control Program 2860 kW; and

b. For the remaining hours of the test loaded 2340 kW and 2600 kW.

(continued)

Quad Cities 1 and 2 3.8.1-12 Amendment No. 199/195

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.16 -------------------NOTES-------------------

1. This Surveillance shall be performed within 5 minutes of shutting down the DG after the DG has operated 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months loaded 2340 kW.

Momentary transients below the load limit do not invalidate this test.

2. All DG starts may be preceded by an engine prelube period.

3. A single test of the common DG at the specified Frequency will satisfy the Surveillance for both units.

Verify each DG starts and achieves: 24 months

a. In 13 seconds, voltage 3952 and frequency 58.8 Hz; and

b. Steady state voltage 3952 V and 4368 V and frequency 58.8 Hz and 61.2 Hz.

SR 3.8.1.17 Verify each DG: 24 months

a. Synchronizes with offsite power source while loaded with emergency loads upon a simulated restoration of offsite power;

b. Transfers loads to offsite power source; and

c. Returns to ready-to-load operation.

(continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.8.1-13 Amendment No. 206/202

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.18 Verify interval between each sequenced load 24 months block is 90% of the design interval for each load sequence time delay relay.

SR 3.8.1.19 -------------------NOTE--------------------

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

Verify, on an actual or simulated loss of 24 months offsite power signal in conjunction with an actual or simulated ECCS initiation signal:

a. De-energization of emergency buses;

b. Load shedding from emergency buses; and In accordance with the Surveillance Frequency

c. DG auto-starts from standby condition Control Program and:

1. energizes permanently connected loads in 13 seconds,

2. energizes auto-connected emergency loads including through time delay relays, where applicable,

3. maintains steady state voltage 3952 V and 4368 V,

4. maintains steady state frequency 58.8 Hz and 61.2 Hz, and

5. supplies permanently connected and auto-connected emergency loads for 5 minutes.

(continued)

Quad Cities 1 and 2 3.8.1-14 Amendment No. 206/202

AC SourcesOperating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.20 -------------------NOTE--------------------

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

Verify, when started simultaneously from 10 years standby condition, each DG achieves, in In accordance with the 13 seconds, voltage 3952 V and Surveillance Frequency frequency 58.8 Hz. Control Program SR 3.8.1.21 -------------------NOTE--------------------

When the opposite unit is in MODE 4 or 5, or moving recently irradiated fuel assemblies in secondary containment, the following opposite unit SRs are not required to be performed: SR 3.8.1.3, SR 3.8.1.10 through SR 3.8.1.12, and SR 3.8.1.14 through SR 3.8.1.17.

For required opposite unit AC electrical In accordance power sources, the SRs of the opposite with applicable unit's Specification 3.8.1, except SRs SR 3.8.1.9, SR 3.8.1.13, SR 3.8.1.18, SR 3.8.1.19, and SR 3.8.1.20, are applicable.

Quad Cities 1 and 2 3.8.1-15 Amendment No. 233/229

Diesel Fuel Oil and Starting Air 3.8.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and D.1 Declare associated DG Immediately associated Completion inoperable.

Time of Condition A, B, or C not met.

OR One or more DGs with stored diesel fuel oil or starting air subsystem not within limits for reasons other than Condition A, B, or C.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.3.1 Verify fuel oil properties of new and In accordance stored fuel oil are tested in accordance with the Diesel with, and maintained within the limits of, Fuel Oil the Diesel Fuel Oil Testing Program. Testing Program SR 3.8.3.2 Verify each required DG air start receiver 31 days pressure is 230 psig.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.8.3-2 Amendment No. 199/195

DC SourcesOperating 3.8.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.4.1 Verify battery terminal voltage on float 7 days charge is:

a. 260.4 VDC for each 250 VDC subsystem; and

b. 125.9 VDC for each 125 VDC subsystem.

SR 3.8.4.2 Verify no visible corrosion at battery 92 days terminals and connectors.

OR Verify battery connection resistance is 1.5E-4 ohm for inter-cell connections and 1.5E-4 ohm for terminal connections.

SR 3.8.4.3 Verify battery cells, cell plates, and 24 months racks show no visual indication of physical damage or abnormal deterioration that could degrade battery performance.

SR 3.8.4.4 Remove visible corrosion and verify battery 24 months cell to cell and terminal connections are coated with anti-corrosion material.

SR 3.8.4.5 Verify battery connection resistance is 24 months 1.5E-4 ohm for inter-cell connections and 1.5E-4 ohm for terminal connections.

(continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.8.4-4 Amendment No. 199/195

DC SourcesOperating 3.8.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.4.6 Verify each required battery charger 24 months supplies:

a. 250 amps at 250 VDC for 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for the 250 VDC subsystems; and

b. 200 amps at 125 VDC for 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for the 125 VDC subsystems.

SR 3.8.4.7 -------------------NOTE--------------------

The modified performance discharge test in SR 3.8.4.8 may be performed in lieu of the service test in SR 3.8.4.7 provided the modified performance discharge test completely envelopes the service test.

Verify battery capacity is adequate to 24 months supply, and maintain in OPERABLE status, the required emergency loads for the design duty cycle when subjected to a battery service test.

(continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.8.4-5 Amendment No. 199/195

DC SourcesOperating 3.8.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.4.8 Verify battery capacity is 80% of the 60 months manufacturer's rating for the 125 VDC In accordance with the batteries or the minimum acceptable battery AND Surveillance Frequency capacity from the load profile for the Control Program 250 VDC batteries when subjected to a 12 months when performance discharge test or a modified battery shows performance discharge test. degradation or has reached 85%

of expected life with capacity

< 100% of manufacturer's rating AND 24 months when battery has reached 85% of the expected life with capacity 100%

of manufacturer's rating Quad Cities 1 and 2 3.8.4-6 Amendment No. 199/195

Battery Cell Parameters 3.8.6 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.6.1 Verify battery cell parameters meet 7 days Table 3.8.6-1 Category A limits.

SR 3.8.6.2 Verify battery cell parameters meet 92 days Table 3.8.6-1 Category B limits.

AND Once within 7 days after battery discharge

< 105 V for 125 V batteries and

< 210 V for 250 V batteries AND Once within 7 days after battery overcharge

> 150 V for 125 V batteries and

> 300 V for 250 V batteries SR 3.8.6.3 Verify average electrolyte temperature of 92 days representative cells is > 65°F.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.8.6-3 Amendment No. 199/195

Distribution SystemsOperating 3.8.7 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.7.1 Verify correct breaker alignments and 7 days voltage to required AC and DC electrical In accordance with the power distribution subsystems. Surveillance Frequency Control Program Quad Cities 1 and 2 3.8.7-3 Amendment No. 199/195

Distribution SystemsShutdown 3.8.8 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2.2 Suspend movement of Immediately recently irradiated fuel assemblies in the secondary containment.

AND A.2.3 Initiate action to Immediately suspend operations with a potential for draining the reactor vessel.

AND A.2.4 Initiate actions to Immediately restore required AC and DC electrical power distribution subsystems to OPERABLE status.

AND A.2.5 Declare associated Immediately required shutdown cooling subsystem(s) inoperable and not in operation.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.8.1 Verify correct breaker alignments and 7 days voltage to required AC and DC electrical In accordance with the power distribution subsystems. Surveillance Frequency Control Program Quad Cities 1 and 2 3.8.8-2 Amendment No. 233/229

Refueling Equipment Interlocks 3.9.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.1.1 Perform CHANNEL FUNCTIONAL TEST on each of 7 days the following required refueling equipment In accordance with the interlock inputs: Surveillance Frequency Control Program

a. All-rods-in,

b. Refuel platform position,

c. Refuel platform fuel grapple, fuel loaded,

d. Refuel platform fuel grapple fully retracted position,

e. Refuel platform frame mounted hoist, fuel loaded, and

f. Refuel platform monorail mounted hoist, fuel loaded.

Quad Cities 1 and 2 3.9.1-2 Amendment No. 199/195

Refuel Position One-Rod-Out Interlock 3.9.2 3.9 REFUELING OPERATIONS 3.9.2 Refuel Position One-Rod-Out Interlock LCO 3.9.2 The refuel position one-rod-out interlock shall be OPERABLE.

APPLICABILITY: MODE 5 with the reactor mode switch in the refuel position and any control rod withdrawn.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Refuel position one- A.1 Suspend control rod Immediately rod-out interlock withdrawal.

inoperable.

AND A.2 Initiate action to Immediately fully insert all insertable control rods in core cells containing one or more fuel assemblies.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.2.1 Verify reactor mode switch locked in Refuel 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months position.

(continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.9.2-1 Amendment No. 199/195

Refuel Position One-Rod-Out Interlock 3.9.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.2.2 ------------------NOTE---------------------

Not required to be performed until 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after any control rod is withdrawn. In accordance with the

Surveillance Frequency Control Program Perform CHANNEL FUNCTIONAL TEST. 7 days Quad Cities 1 and 2 3.9.2-2 Amendment No. 199/195

Control Rod Position 3.9.3 3.9 REFUELING OPERATIONS 3.9.3 Control Rod Position LCO 3.9.3 All control rods shall be fully inserted.

APPLICABILITY: When loading fuel assemblies into the core.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more control A.1 Suspend loading fuel Immediately rods not fully assemblies into the inserted. core.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.3.1 Verify all control rods are fully inserted. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.9.3-1 Amendment No. 199/195

Control Rod OPERABILITYRefueling 3.9.5 3.9 REFUELING OPERATIONS 3.9.5 Control Rod OPERABILITYRefueling LCO 3.9.5 Each withdrawn control rod shall be OPERABLE.

APPLICABILITY: MODE 5.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more withdrawn A.1 Initiate action to Immediately control rods fully insert inoperable. inoperable withdrawn control rods.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.5.1 -------------------NOTE--------------------

Not required to be performed until 7 days after the control rod is withdrawn.

Insert each withdrawn control rod at least 7 days one notch.

SR 3.9.5.2 Verify each withdrawn control rod scram 7 days accumulator pressure is 940 psig.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.9.5-1 Amendment No. 199/195

RPV Water LevelIrradiated Fuel 3.9.6 3.9 REFUELING OPERATIONS 3.9.6 Reactor Pressure Vessel (RPV) Water LevelIrradiated Fuel LCO 3.9.6 RPV water level shall be 23 ft above the top of the RPV flange.

APPLICABILITY: During movement of irradiated fuel assemblies within the RPV.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. RPV water level not A.1 Suspend movement of Immediately within limit. irradiated fuel assemblies within the RPV.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.6.1 Verify RPV water level is 23 ft above the 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months top of the RPV flange.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.9.6-1 Amendment No. 199/195

RPV Water LevelNew Fuel or Control Rods 3.9.7 3.9 REFUELING OPERATIONS 3.9.7 Reactor Pressure Vessel (RPV) Water LevelNew Fuel or Control Rods LCO 3.9.7 RPV water level shall be 23 ft above the top of irradiated fuel assemblies seated within the RPV.

APPLICABILITY: During movement of new fuel assemblies or handling of control rods within the RPV, when irradiated fuel assemblies are seated within the RPV.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. RPV water level not A.1 Suspend movement of Immediately within limit. new fuel assemblies and handling of control rods within the RPV.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.7.1 Verify RPV water level is 23 ft above the 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months top of irradiated fuel assemblies seated In accordance with the within the RPV. Surveillance Frequency Control Program Quad Cities 1 and 2 3.9.7-1 Amendment No. 199/195

RHRHigh Water Level 3.9.8 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.8.1 Monitor reactor coolant temperature. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months SR 3.9.8.2 Verify each required RHR shutdown cooling 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months subsystem manual and power operated valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position or can be aligned to the correct position.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.9.8-3 Amendment No. 199/195

RHRLow Water Level 3.9.9 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.9.1 Monitor reactor coolant temperature. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months SR 3.9.9.2 Verify each required RHR shutdown cooling 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months subsystem manual and power operated valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position or can be aligned to the correct position.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.9.9-3 Amendment No. 199/195

Reactor Mode Switch Interlock Testing 3.10.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.3.1 Place the reactor 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months mode switch in the shutdown position.

OR A.3.2 --------NOTE---------

Only applicable in MODE 5.

Place the reactor 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months mode switch in the refuel position.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.10.1.1 Verify all control rods are fully inserted 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months in core cells containing one or more fuel assemblies.

SR 3.10.1.2 Verify no CORE ALTERATIONS are in progress. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.10.1-2 Amendment No. 199/195

Single Control Rod WithdrawalHot Shutdown 3.10.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.10.2.1 Perform the applicable SRs for the required According to LCOs. the applicable SRs SR 3.10.2.2 -------------------NOTE--------------------

Not required to be met if SR 3.10.2.1 is satisfied for LCO 3.10.2.d.1 requirements.

Verify all control rods, other than the 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months control rod being withdrawn, in a five by five array centered on the control rod being withdrawn, are disarmed.

SR 3.10.2.3 Verify all control rods, other than the 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months control rod being withdrawn, are fully inserted.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.10.2-3 Amendment No. 199/195

Single Control Rod WithdrawalCold Shutdown 3.10.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. One or more of the B.1 Suspend withdrawal of Immediately above requirements not the control rod and met with the affected removal of associated control rod not CRD.

insertable.

AND B.2.1 Initiate action to Immediately fully insert all control rods.

OR B.2.2 Initiate action to Immediately satisfy the requirements of this LCO.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.10.3.1 Perform the applicable SRs for the required According to LCOs. the applicable SRs SR 3.10.3.2 -------------------NOTE-------------------

Not required to be met if SR 3.10.3.1 is satisfied for LCO 3.10.3.c.1 requirements.

Verify all control rods, other than the 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months control rod being withdrawn, in a five by In accordance with the five array centered on the control rod Surveillance Frequency being withdrawn, are disarmed. Control Program (continued)

Quad Cities 1 and 2 3.10.3-3 Amendment No. 199/195

Single Control Rod WithdrawalCold Shutdown 3.10.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.10.3.3 Verify all control rods, other than the 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months control rod being withdrawn, are fully inserted.

SR 3.10.3.4 -------------------NOTE-------------------

Not required to be met if SR 3.10.3.1 is satisfied for LCO 3.10.3.b.1 requirements.

Verify a control rod withdrawal block is 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months inserted.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.10.3-4 Amendment No. 199/195

Single CRD RemovalRefueling 3.10.4 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2.1 Initiate action to Immediately fully insert all control rods.

OR A.2.2 Initiate action to Immediately satisfy the requirements of this LCO.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.10.4.1 Verify all control rods, other than the 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months control rod withdrawn for the removal of the associated CRD, are fully inserted.

SR 3.10.4.2 Verify all control rods, other than the 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months control rod withdrawn for the removal of the associated CRD, in a five by five array centered on the control rod withdrawn for the removal of the associated CRD, are disarmed.

SR 3.10.4.3 Verify a control rod withdrawal block is 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months inserted.

(continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.10.4-2 Amendment No. 199/195

Single CRD RemovalRefueling 3.10.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.10.4.4 Perform SR 3.1.1.1. According to SR 3.1.1.1 SR 3.10.4.5 Verify no other CORE ALTERATIONS are in 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months progress.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.10.4-3 Amendment No. 199/195

Multiple Control Rod WithdrawalRefueling 3.10.5 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.3.1 Initiate action to Immediately fully insert all control rods in core cells containing one or more fuel assemblies.

OR A.3.2 Initiate action to Immediately satisfy the requirements of this LCO.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.10.5.1 Verify the four fuel assemblies are removed 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from core cells associated with each control rod or CRD removed.

SR 3.10.5.2 Verify all other control rods in core cells 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months containing one or more fuel assemblies are fully inserted.

SR 3.10.5.3 -------------------NOTE--------------------

Only required to be met during fuel loading.

Verify fuel assemblies being loaded are in 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months compliance with an approved spiral reload sequence.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.10.5-2 Amendment No. 199/195

SDM TestRefueling 3.10.7 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.10.7.2 -------------------NOTE--------------------

Not required to be met if SR 3.10.7.3 satisfied.

Perform the MODE 2 applicable SRs for According to LCO 3.3.2.1, Function 2 of Table 3.3.2.1-1. the applicable SRs SR 3.10.7.3 -------------------NOTE--------------------

Not required to be met if SR 3.10.7.2 satisfied.

Verify movement of control rods is in During control compliance with the approved control rod rod movement sequence for the SDM test by a second licensed operator or other qualified member of the technical staff.

SR 3.10.7.4 Verify no other CORE ALTERATIONS are in 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months progress.

(continued)

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.10.7-3 Amendment No. 199/195

SDM TestRefueling 3.10.7 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.10.7.5 Verify each withdrawn control rod does not Each time the go to the withdrawn overtravel position. control rod is withdrawn to "full out" position AND Prior to satisfying LCO 3.10.7.c requirement after work on control rod or CRD System that could affect coupling SR 3.10.7.6 Verify CRD charging water header pressure 7 days 940 psig.

In accordance with the Surveillance Frequency Control Program Quad Cities 1 and 2 3.10.7-4 Amendment No. 199/195

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.13 Control Room Envelope Habitability Program (continued) maintenance.

c. Requirements of (i) determining the unfiltered air inleakage past the CRE boundary into the CRE in accordance with the testing methods and at the Frequencies specified in Section C.1 and C.2 of Regulatory Guide 1.197, Demonstrating Control Room Envelope Integrity at Nuclear Power Reactors, Revision 0, May 2003, and (ii) assessing CRE habitability at the Frequencies specified in Section C.1 and C.2 of Regulatory Guide 1.197, Revision 0.

d. Measurement, at designated locations, of the CRE pressure relative to all external areas adjacent to the CRE boundary during the pressurization mode of operation of the CREV system, operating at the flow rate required by the VFTP, at a Frequency of 24 months. The results shall be trended and used as part of the 24 month assessment of the CRE boundary.

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

f. The provisions of SR 3.0.2 are applicable to the Frequencies for assessing CRE habitability, determining CRE unfiltered inleakage, and measuring CRE pressure and assessing the CRE boundary as required by paragraph c and d, respectively.

5.5.14 Surveillance Frequency Control Program This program provides controls for Surveillance Frequencies. The program shall ensure that Surveillance Requirements specified in the Technical Specifications are performed at intervals sufficient to assure the associated Limiting Conditions for Operation are met.

a. The Surveillance Frequency Control Program shall contain a list of Frequencies of those Surveillance Requirements for which the Frequency is controlled by the program.

b. Changes to the Frequencies listed in the Surveillance Frequency Control Program shall be made in accordance with NEI 04-10, "Risk-Informed Method for Control of Surveillance Frequencies," Revision 1.

c. The provisions of Surveillance Requirements 3.0.2 and 3.0.3 are applicable to the Frequencies established in the Surveillance Frequency Control Program.

Quad Cities 1 and 2 5.5-13 Amendment No. 238/233

ATTACHMENT 4 Markup of Proposed Technical Specifications Bases Pages Quad Cities Nuclear Power Station, Units 1 and 2 Renewed Facility Operating License Nos. DPR-29 and DPR-30 REVISED TECHNICAL SPECIFICATION BASES PAGES (NOTE: TS Bases pages are provided for information only.)

B 3.1.3-7 B 3.3.1.3-9 B 3.3.6.3-6 B 3.5.1-17 B 3.6.4.1-5 B 3.8.3-2 B 3.1.3-8 B 3.3.2.1-4 B 3.3.7.1-11 B 3.5.2-5 B 3.6.4.1-6 B 3.8.3-6 B 3.1.4-5 B 3.3.2.1-5 B 3.3.7.1-12 B 3.5.2-6 B 3.6.4.2-6 B 3.8.4-10 B 3.1.5-5 B 3.3.2.1-9 B 3.3.7.1-13 B 3.5.3-4 B 3.6.4.2-7 B 3.8.4-11 B 3.1.6-5 B 3.3.2.1-10 B 3.3.7.2-5 B 3.5.3-5 B 3.6.4.3-6 B 3.8.4-12 B 3.1.7-4 B 3.3.2.1-11 B 3.3.7.2-6 B 3.5.3-6 B 3.7.1-6 B 3.8.4-13 B 3.1.7-5 B 3.3.2.1-12 B 3.3.7.2-7 B 3.6.1.1-4 B 3.7.2-4 B 3.8.4-14 B 3.1.7-6 B 3.3.2.1-14 B 3.3.8.1-7 B 3.6.1.1-5 B 3.7.3-3 B 3.8.4-15 B 3.1.7-7 B 3.3.2.2-6 B 3.3.8.1-8 B 3.6.1.2-7 B 3.7.4-7 B 3.8.6-3 B 3.1.8-4 B 3.3.2.2-7 B 3.3.8.2-6 B 3.6.1.2-8 B 3.7.5-4 B 3.8.6-4 B 3.1.8-5 B 3.3.2.2-8 B 3.3.8.2-7 B 3.6.1.3-10 B 3.7.6-3 B 3.8.7-10 B 3.2.1-3 B 3.3.3.1-10 B 3.4.1-6 B 3.6.1.3-11 B 3.7.7-3 B 3.8.8-4 B 3.2.2-4 B 3.3.3.1-11 B 3.4.2-4 B 3.6.1.3-12 B 3.7.7-4 B 3.9.1-5 B 3.2.3-3 B 3.3.3.1-12 B 3.4.3-6 B 3.6.1.3-13 B 3.7.8-2 B 3.9.2-3 B 3.3.1.1-27 B 3.3.4.1-8 B 3.4.3-7 B 3.6.1.3-14 B 3.7.9-3 B 3.9.2-4 B 3.3.1.1-28 B 3.3.4.1-9 B 3.4.4-5 B 3.6.1.3-15 B 3.7.9-4 B 3.9.3-3 B 3.3.1.1-29 B 3.3.4.1-10 B 3.4.5-3 B 3.6.1.4-2 B 3.8.1-18 B 3.9.5-3 B 3.3.1.1-30 B 3.3.5.1-40 B 3.4.5-5 B 3.6.1.5-3 B 3.8.1-19 B 3.9.6-3 B 3.3.1.1-31 B 3.3.5.1-41 B 3.4.6-4 B 3.6.1.6-3 B 3.8.1-20 B 3.9.7-3 B 3.3.1.1-32 B 3.3.5.1-42 B 3.4.7-5 B 3.6.1.6-4 B 3.8.1-21 B 3.9.8-4 B 3.3.1.1-33 B 3.3.5.2-11 B 3.4.8-5 B 3.6.1.7-5 B 3.8.1-22 B 3.9.8-5 B 3.3.1.1-34 B 3.3.5.2-12 B 3.4.9-7 B 3.6.1.7-6 B 3.8.1-23 B 3.9.9-4 B 3.3.1.1-35 B 3.3.5.2-13 B 3.4.9-8 B 3.6.1.8-5 B 3.8.1-24 B 3.9.9-5 B 3.3.1.1-36 B 3.3.6.1-25 B 3.4.9-9 B 3.6.1.8-6 B 3.8.1-25 B 3.10.1-5 B 3.3.1.2-6 B 3.3.6.1-26 B 3.4.10-3 B 3.6.2.1-5 B 3.8.1-27 B 3.10.2-4 B 3.3.1.2-7 B 3.3.6.1-27 B 3.5.1-10 B 3.6.2.2-3 B 3.8.1-28 B 3.10.2-5 B 3.3.1.2-8 B 3.3.6.1-28 B 3.5.1-11 B 3.6.2.3-4 B 3.8.1-29 B 3.10.3-5 B 3.3.1.2-9 B 3.3.6.2-10 B 3.5.1-12 B 3.6.2.4-4 B 3.8.1-30 B 3.10.4-5 B 3.3.1.2-10 B 3.3.6.2-11 B 3.5.1-14 B 3.6.2.5-3 B 3.8.1-31 B 3.10.5-3 B 3.3.1.3-7 B 3.3.6.2-12 B 3.5.1-15 B 3.6.3.1-3 B 3.8.1-32 B 3.10.7-5 B 3.3.1.3-8 B 3.3.6.3-5 B 3.5.1-16 B 3.6.4.1-4 B 3.8.1-33 B 3.10.7-6

Control Rod OPERABILITY B 3.1.3 BASES ACTIONS D.1 and D.2 (continued) followed under these conditions, as described in the Bases for LCO 3.1.6. The allowed Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is acceptable, considering the low probability of a CRDA occurring.

E.1 If any Required Action and associated Completion Time of Condition A, C, or D are not met, or there are nine or more inoperable control rods, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . This ensures all insertable control rods are inserted and places the reactor in a condition that does not require the active function (i.e., scram) of the control rods. The number of control rods permitted to be inoperable when operating above 10% RTP (e.g., no CRDA considerations) could be more than the value specified, but the occurrence of a large number of inoperable control rods could be indicative of a generic problem, and investigation and resolution of the potential problem should be undertaken. The allowed Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.1.3.1 REQUIREMENTS The position of each control rod must be determined to ensure adequate information on control rod position is available to the operator for determining control rod The Frequency may be based OPERABILITY and controlling rod patterns. Control rod on factors such as operating position may be determined by the use of OPERABLE position experience, equipment reliability, or plant risk, and is controlled indicators, by moving control rods to a position with an under the Surveillance OPERABLE indicator (full-in, full-out, or numeric Frequency Control Program. indicators), by verifying the indicators one notch "out" and one notch "in" are OPERABLE, or by the use of other appropriate methods. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency of this SR is based on operating experience related to expected changes in control rod position and the availability of control rod position indications in the control room.

(continued)

Quad Cities 1 and 2 B 3.1.3-7 Revision 0

Control Rod OPERABILITY B 3.1.3 BASES SURVEILLANCE SR 3.1.3.2 REQUIREMENTS (continued) Deleted SR 3.1.3.3 Control rod insertion capability is demonstrated by inserting each partially or fully withdrawn control rod at least one notch and observing that the control rod moves.

The Frequency may be based The control rod may then be returned to its original on factors such as operating position. This ensures the control rod is not stuck and is experience, equipment reliability, or plant risk, and is controlled free to insert on a scram signal. This Surveillance is not under the Surveillance required when THERMAL POWER is less than or equal to the Frequency Control Program. actual LPSP of the RWM, since the notch insertions may not be compatible with the requirements of the analyzed rod position sequence (LCO 3.1.6) and the RWM (LCO 3.3.2.1).

The 31 day Frequency takes into account operating experience related to changes in CRD performance. At any time, if a control rod is immovable, a determination of that control rod's trippability (OPERABILITY) must be made and appropriate action taken.

This SR is modified by a Note that allows 31 days after withdrawal of the control rod and increasing power to above the LPSP, to perform the Surveillance. This acknowledges that the control rod must be first withdrawn and THERMAL POWER must be increased to above the LPSP before performance of the Surveillance, and therefore, the Note avoids potential conflicts with SR 3.0.3 and SR 3.0.4.

SR 3.1.3.4 Verifying that the scram time for each control rod to 90%

insertion is 7 seconds provides reasonable assurance that the control rod will insert when required during a DBA or transient, thereby completing its shutdown function. This SR is performed in conjunction with the control rod scram time testing of SR 3.1.4.1, SR 3.1.4.2, SR 3.1.4.3, and SR 3.1.4.4. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.1.1, "Reactor Protection System (RPS)

(continued)

Quad Cities 1 and 2 B 3.1.3-8 Revision 39

Control Rod Scram Times B 3.1.4 BASES SURVEILLANCE SR 3.1.4.2 REQUIREMENTS (continued) Additional testing of a sample of control rods is required to verify the continued performance of the scram function during the cycle. A representative sample contains at least 10% of the control rods. The sample remains representative if no more than 20% of the control rods in the sample tested are determined to be "slow." With more than 20% of the sample declared to be "slow" per the criteria in Table 3.1.4-1, additional control rods are tested until this 20% criterion (i.e., 20% of the entire sample size) is The Frequency may be based satisfied, or until the total number of "slow" control rods on factors such as operating experience, equipment reliability, (throughout the core, from all surveillances) exceeds the or plant risk, and is controlled LCO limit. For planned testing, the control rods selected under the Surveillance for the sample should be different for each test. Data from Frequency Control Program. inadvertent scrams should be used whenever possible to avoid unnecessary testing at power, even if the control rods with data may have been previously tested in a sample. The 120 day Frequency is based on operating experience that has shown control rod scram times do not significantly change over an operating cycle. This Frequency is also reasonable based on the additional Surveillances done on the CRDs at more frequent intervals in accordance with LCO 3.1.3 and LCO 3.1.5, "Control Rod Scram Accumulators."

SR 3.1.4.3 When work that could affect the scram insertion time is performed on a control rod or the CRD System, testing must be done to demonstrate that each affected control rod retains adequate scram performance over the range of applicable reactor pressures from zero to the maximum permissible pressure. The scram testing must be performed once before declaring the control rod OPERABLE. The required scram time testing must demonstrate the affected control rod is still within acceptable limits. The scram time limits for reactor pressures < 800 psig are found in the Technical Requirements Manual (Ref. 8) and are established based on a high probability of meeting the acceptance criteria at reactor pressures 800 psig. Limits for 800 psig are found in Table 3.1.4-1. If testing demonstrates the affected control rod does not meet these limits, but is within the 7-second limit of Table 3.1.4-1, Note 2, the control rod can be declared OPERABLE and "slow."

(continued)

Quad Cities 1 and 2 B 3.1.4-5 Revision 0

Control Rod Scram Accumulators B 3.1.5 BASES ACTIONS D.1 (continued) that all insertable control rods are inserted and that the reactor is in a condition that does not require the active function (i.e., scram) of the control rods. This Required Action is modified by a Note stating that the action is not applicable if all control rods associated with the inoperable scram accumulators are fully inserted, since the function of the control rods has been performed.

SURVEILLANCE SR 3.1.5.1 REQUIREMENTS SR 3.1.5.1 requires that the accumulator pressure be checked every 7 days to ensure adequate accumulator pressure exists periodically to provide sufficient scram force. The primary indicator of accumulator OPERABILITY is the accumulator pressure. A minimum accumulator pressure is specified, below which the The Frequency may be based capability of the accumulator to perform its intended on factors such as operating function becomes degraded and the accumulator is considered experience, equipment reliability, inoperable. The minimum accumulator pressure of 940 psig is or plant risk, and is controlled under the Surveillance well below the expected pressure of 1100 psig (Ref. 2).

Frequency Control Program. Declaring the accumulator inoperable when the minimum pressure is not maintained ensures that significant degradation in scram times does not occur. The 7 day Frequency has been shown to be acceptable through operating experience and takes into account indications available in the control room.

REFERENCES 1. UFSAR, Section 4.6.3.4.2.1.

2. Letter, from E.Y. Gibo (GE) to P Chenell (ComEd),

"Generic Basis for HCU Scram Accumulator Minimum Setpoint Pressure," April 10, 1998.

Quad Cities 1 and 2 B 3.1.5-5 Revision 0

Rod Pattern Control B 3.1.6 BASES ACTIONS B.1 and B.2 (continued)

When nine or more OPERABLE control rods are not in compliance with the analyzed rod position sequence, the reactor mode switch must be placed in the shutdown position within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . With the mode switch in shutdown, the reactor is shut down, and as such, does not meet the applicability requirements of this LCO. The allowed Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is reasonable to allow insertion of control rods to restore compliance, and is appropriate relative to the low probability of a CRDA occurring with the control rods out of sequence.

SURVEILLANCE SR 3.1.6.1 periodically REQUIREMENTS The control rod pattern is verified to be in compliance with the analyzed rod position sequence at a 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency to ensure the assumptions of the CRDA analyses are met. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency was developed considering that the primary check on compliance with the analyzed rod position sequence is performed by the RWM (LCO 3.3.2.1), which provides control rod blocks to enforce the required sequence and is required to be OPERABLE when operating at 10% RTP.

REFERENCES 1. UFSAR, Section 15.4.10.

The Frequency may be based on factors such as operating 2. XN-NF-80-19(P)(A), Volume 1, Supplement 2, Section 7.1 experience, equipment reliability, Exxon Nuclear Methodology for Boiling Water Reactor-or plant risk, and is controlled under the Surveillance Neutronics Methods for Design and Analysis, (as Frequency Control Program. specified in Technical Specification 5.6.5).

The RWM

3. NEDE-24011-P-A, "GE Standard Application for Reactor Fuel," (as specified in Technical Specification 5.6.5).

4. Letter from T.A. Pickens (BWROG) to G.C. Lainas (NRC),

"Amendment 17 to General Electric Licensing Topical Report NEDE-24011-P-A," BWROG-8644, August 15, 1986.

5. NFSR-0091, Benchmark of CASMO/MICROBURN BWR Nuclear Design Methods, Commonwealth Edison Topical Report, (as specified in Technical Specification 5.6.5).

(continued)

Quad Cities 1 and 2 B 3.1.6-5 Revision 21

SLC System B 3.1.7 BASES ACTIONS C.1 (continued)

If any Required Action and associated Completion Time is not met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.1.7.1, SR 3.1.7.2, and SR 3.1.7.3 REQUIREMENTS SR 3.1.7.1 through SR 3.1.7.3 are 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Surveillances verifying certain characteristics of the SLC System (e.g.,

the volume and temperature of the borated solution in the storage tank), thereby ensuring SLC System OPERABILITY without disturbing normal plant operation. These Surveillances ensure that the proper borated solution volume and temperature, including the temperature of the pump The Frequency may be based suction piping, are maintained. Maintaining a minimum on factors such as operating specified borated solution temperature is important in experience, equipment reliability, or plant risk, and is controlled ensuring that the boron remains in solution and does not under the Surveillance precipitate out in the storage tank or in the pump suction Frequency Control Program. piping. The temperature versus concentration curve of Figure 3.1.7-2 ensures that a 10°F margin will be maintained above the saturation temperature. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on operating experience and has shown there are relatively slow variations in the measured parameters of volume and temperature.

SR 3.1.7.4 and SR 3.1.7.6 SR 3.1.7.4 verifies the continuity of the explosive charges in the injection valves to ensure that proper operation will occur if required. Other administrative controls, such as those that limit the shelf life of the explosive charges, (continued)

Quad Cities 1 and 2 B 3.1.7-4 Revision 31

SLC System B 3.1.7 BASES SURVEILLANCE SR 3.1.7.4 and SR 3.1.7.6 (continued)

REQUIREMENTS must be followed. The 31 day Frequency is based on operating experience and has demonstrated the reliability of the explosive charge continuity.

SR 3.1.7.6 verifies that each valve in the system is in its correct position, but does not apply to the squib (i.e.,

explosive) valves. Verifying the correct alignment for manual valves in the SLC System flow path provides assurance that the proper flow paths will exist for system operation.

A valve is also allowed to be in the nonaccident position provided it can be aligned to the accident position from the control room, or locally by a dedicated operator at the valve control. This is acceptable since the SLC System is a manually initiated system. This Surveillance also does not apply to valves that are locked, sealed, or otherwise secured in position since they are verified to be in the The Frequency may be based correct position prior to locking, sealing, or securing.

on factors such as operating This verification of valve alignment does not require any experience, equipment reliability, testing or valve manipulation; rather, it involves or plant risk, and is controlled under the Surveillance verification that those valves capable of being Frequency Control Program. mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The 31 day Frequency is based on engineering judgment and is consistent with the procedural controls governing valve operation that ensures correct valve positions.

SR 3.1.7.5 This Surveillance requires an examination of the sodium pentaborate solution by using chemical analysis to ensure that the proper concentration of sodium pentaborate exists in the storage tank. SR 3.1.7.5 must be performed anytime boron or water is added to the storage tank solution to determine that the sodium pentaborate solution concentration is within the specified limits. SR 3.1.7.5 must also be performed anytime the temperature is restored to within the limits of Figure 3.1.7-2, to ensure that no significant boron precipitation occurred. The 31 day Frequency of this Surveillance is appropriate because of the relatively slow variation of sodium pentaborate concentration between surveillances.

(continued)

Quad Cities 1 and 2 B 3.1.7-5 Revision 31

SLC System B 3.1.7 BASES SURVEILLANCE SR 3.1.7.7 REQUIREMENTS (continued) Demonstrating that each SLC System pump develops a flow rate 40 gpm at a discharge pressure 1275 psig ensures that pump performance has not degraded during the fuel cycle.

This minimum pump flow rate requirement ensures that, when combined with the sodium pentaborate solution concentration requirements, the rate of negative reactivity insertion from the SLC System will adequately compensate for the positive reactivity effects encountered during power reduction, cooldown of the moderator, and xenon decay. This test confirms one point on the pump design curve and is indicative of overall performance. Such inservice tests confirm component OPERABILITY, and detect incipient failures by indicating abnormal performance. The Frequency of this Surveillance is in accordance with the Inservice Testing Program.

SR 3.1.7.8 and SR 3.1.7.9 These Surveillances ensure that there is a functioning flow path from the boron solution storage tank to the RPV, including the firing of an explosive valve. The replacement charge for the explosive valve shall be from the same manufactured batch as the one fired or from another batch that has been certified by having one of that batch successfully fired. The pump and explosive valve tested The Frequency may be based should be alternated such that both complete flow paths are on factors such as operating tested every 48 months at alternating 24 month intervals.

experience, equipment reliability, or plant risk, and is controlled The Surveillance may be performed in separate steps to under the Surveillance prevent injecting boron into the RPV. An acceptable method Frequency Control Program. for verifying flow from the pump to the RPV is to pump demineralized water from a test tank through one SLC subsystem and into the RPV. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency; therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

(continued)

Quad Cities 1 and 2 B 3.1.7-6 Revision 31

SLC System B 3.1.7 BASES SURVEILLANCE SR 3.1.7.8 and SR 3.1.7.9 (continued)

REQUIREMENTS Demonstrating that all heat traced piping between the boron The Frequency may be based solution storage tank and the suction inlet to the injection on factors such as operating pumps is unblocked ensures that there is a functioning flow experience, equipment reliability, path for injecting the sodium pentaborate solution. An or plant risk, and is controlled under the Surveillance acceptable method for verifying that the suction piping is Frequency Control Program. If unblocked is to pump from the storage tank to the storage tank.

The 24 month Frequency is acceptable since there is a low probability that the subject piping will be blocked due to precipitation of the boron from solution in the heat traced piping. This is especially true in light of the temperature verification of this piping required by SR 3.1.7.3.

However, if, in performing SR 3.1.7.3, it is determined that the temperature of this piping has fallen below the specified minimum, SR 3.1.7.9 must be performed once within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after the piping temperature is restored to within the limits of Figure 3.1.7-2.

SR 3.1.7.10 Enriched sodium pentaborate solution is made by mixing granular, enriched sodium pentaborate with water. Action to verify the actual B-10 enrichment must be performed prior to addition to the SLC tank in order to ensure that the proper B-10 atom percentage is being used. The proper enrichment (i.e., B-10 atom percentage) of the sodium pentabotate is verified, prior to the addition to the SLC tank, by use of a certificate of conformance provided by the supplier for each batch of enriched sodium pentaborate. The certificate of conformance will include certification that the enrichment of the sodium pentaborate satisfies the acceptance criterion.

REFERENCES 1. 10 CFR 50.62.

2. UFSAR, Section 9.3.5.3.

3. NUREG-1465, "Accident Source Terms for Light-Water Nuclear Power Plants, Final Report," February 1, 1995.

4. 10 CFR 50.67.

Quad Cities 1 and 2 B 3.1.7-7 Revision 32

SDV Vent and Drain Valves B 3.1.8 BASES ACTIONS C.1 (continued)

Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.1.8.1 REQUIREMENTS During normal operation, the SDV vent and drain valves should be in the open position (except when performing SR 3.1.8.2) to allow for drainage of the SDV piping.

The Frequency may be based Verifying that each valve is in the open position ensures on factors such as operating that the SDV vent and drain valves will perform their experience, equipment reliability, intended functions during normal operation. This SR does or plant risk, and is controlled under the Surveillance not require any testing or valve manipulation; rather, it Frequency Control Program. involves verification that the valves are in the correct position.

The 31 day Frequency is based on engineering judgment and is consistent with the procedural controls governing valve operation, which ensure correct valve positions. Improper valve position (closed) would not affect the isolation function.

SR 3.1.8.2 During a scram, the SDV vent and drain valves should close to contain the reactor water discharged to the SDV piping.

Cycling each valve through its complete range of motion (closed and open) ensures that the valve will function properly during a scram. The 92 day Frequency is based on operating experience and takes into account the level of redundancy in the system design.

SR 3.1.8.3 SR 3.1.8.3 is an integrated test of the SDV vent and drain valves to verify total system performance. After receipt of a simulated or actual scram signal, the closure of the SDV vent and drain valves is verified. The closure time of 30 seconds after receipt of a scram signal is based on the (continued)

Quad Cities 1 and 2 B 3.1.8-4 Revision 0

SDV Vent and Drain Valves B 3.1.8 BASES SURVEILLANCE SR 3.1.8.3 (continued)

REQUIREMENTS bounding leakage case evaluated in the accident analysis The Frequency may be based (Ref. 3). Similarly, after receipt of a simulated or actual on factors such as operating scram reset signal, the opening of the SDV vent and drain experience, equipment reliability, or plant risk, and is controlled valves is verified. The LOGIC SYSTEM FUNCTIONAL TEST in under the Surveillance LCO 3.3.1.1 and the scram time testing of control rods in Frequency Control Program. LCO 3.1.3, "Control Rod OPERABILITY," overlap this Surveillance to provide complete testing of the assumed safety function. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency; therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES 1. UFSAR, Section 4.6.3.3.2.8.

2. 10 CFR 50.67.

3. NUREG-0803, "Generic Safety Evaluation Report Regarding Integrity of BWR Scram System Piping,"

August 1981.

Quad Cities 1 and 2 B 3.1.8-5 Revision 31

APLHGR B 3.2.1 BASES (continued)

ACTIONS A.1 If any APLHGR exceeds the required limits, an assumption regarding an initial condition of the DBA analyses may not be met. Therefore, prompt action should be taken to restore the APLHGR(s) to within the required limits such that the plant operates within analyzed conditions. The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is sufficient to restore the APLHGR(s) to within its limits and is acceptable based on the low probability of a DBA occurring simultaneously with the APLHGR out of specification.

B.1 If the APLHGR cannot be restored to within its required limits within the associated Completion Time, the plant must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, THERMAL POWER must be reduced to < 25% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < 25% RTP in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.2.1.1 periodically REQUIREMENTS APLHGRs are required to be initially calculated within The Frequency may be based 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER is 25% RTP and then every on factors such as operating 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter. They are compared to the specified experience, equipment reliability, limits in the COLR to ensure that the reactor is operating or plant risk, and is controlled within the assumptions of the safety analysis. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months under the Surveillance Frequency Control Program. Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution during normal operation. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance after THERMAL POWER 25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.

(continued)

Quad Cities 1 and 2 B 3.2.1-3 Revision 1

MCPR B 3.2.2 BASES ACTIONS B.1 (continued)

If the MCPR cannot be restored to within its required limits within the associated Completion Time, the plant must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, THERMAL POWER must be reduced to < 25% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < 25% RTP in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.2.2.1 periodically REQUIREMENTS The MCPR is required to be initially calculated within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER is 25% RTP and then every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter. It is compared to the specified limits in the COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution during normal operation. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance after The Frequency may be based on factors such as operating THERMAL POWER 25% RTP is achieved is acceptable given the experience, equipment reliability, large inherent margin to operating limits at low power or plant risk, and is controlled levels.

under the Surveillance Frequency Control Program.

SR 3.2.2.2 Because the transient analyses take credit for conservatism in the scram speed performance, it must be demonstrated that the specific scram speed distribution is consistent with that used in the transient analyses.

For GE methodology, SR 3.2.2.2 determines the value of ,

which is a measure of the actual scram speed distribution compared with the assumed distribution. The MCPR operating limit is then determined based on an interpolation between the applicable limits for Option A (scram times of LCO 3.1.4) and Option B (realistic scram times) analyses. This determination of the parameter for GE methodology must be performed once within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months after each set of scram time tests required by SR 3.1.4.1, SR 3.1.4.2, and SR 3.1.4.4 because the effective scram speed distribution may change (continued)

Quad Cities 1 and 2 B 3.2.2-4 Revision 28

LHGR B 3.2.3 BASES (continued)

ACTIONS A.1 If any LHGR exceeds its required limit, an assumption regarding an initial condition of the fuel design analysis is not met. Therefore, prompt action should be taken to restore the LHGR(s) to within its required limits such that the plant is operating within analyzed conditions.

The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is normally sufficient to restore the LHGR(s) to within its limits and is acceptable based on the low probability of a transient or Design Basis Accident occurring simultaneously with the LHGR out of specification.

B.1 If the LHGR cannot be restored to within its required limits within the associated Completion Time, the plant must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, THERMAL POWER is reduced to < 25% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER TO < 25% RTP in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.2.3.1 periodically REQUIREMENTS The LHGRs are required to be initially calculated within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER is 25% RTP and then every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter. They are compared to the LHGR limits in the COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on both engineering judgment and The Frequency may be based recognition of the slow changes in power distribution on factors such as operating during normal operation. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance after experience, equipment reliability, THERMAL POWER 25% RTP is achieved is acceptable given or plant risk, and is controlled the large inherent margin to operating limits at lower under the Surveillance power levels.

Frequency Control Program.

REFERENCES 1. UFSAR, Chapter 4.

2. UFSAR, Chapter 15.

(continued)

Quad Cities 1 and 2 B 3.2.3-3 Revision 19

RPS Instrumentation B 3.3.1.1 BASES ACTIONS H.1 (continued)

If the channel(s) is not restored to OPERABLE status or placed in trip (or the associated trip system placed in trip) within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. This is done by immediately initiating action to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Control rods in core cells containing no fuel assemblies do not affect the reactivity of the core and are, therefore, not required to be inserted. Action must continue until all insertable control rods in core cells containing one or more fuel assemblies are fully inserted.

SURVEILLANCE As noted at the beginning of the SRs, the SRs for each RPS REQUIREMENTS instrumentation Function are located in the SRs column of Table 3.3.1.1-1.

The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , provided the associated Function maintains RPS trip capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 13) assumption of the average time required to perform channel Surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the RPS will trip when necessary.

SR 3.3.1.1.1 Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read (continued)

Quad Cities 1 and 2 B 3.3.1.1-27 Revision 0

RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.1 (continued)

REQUIREMENTS approximately the same value. Significant deviations between instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

The Frequency may be based on factors such as operating Agreement criteria are determined by the plant staff based experience, equipment reliability, on a combination of the channel instrument uncertainties, or plant risk, and is controlled under the Surveillance including indication and readability. If a channel is Frequency Control Program. outside the criteria, it may be an indication that the instrument has drifted outside its limit.

The Frequency is based upon operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.

SR 3.3.1.1.2 To ensure that the APRMs are accurately indicating the true core average power, the APRMs are calibrated to the reactor power calculated from a heat balance.

An allowance is provided that requires the SR to be performed only at 25% RTP because it is difficult to accurately maintain APRM indication of core THERMAL POWER (continued)

Quad Cities 1 and 2 B 3.3.1.1-28 Revision 9

RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.2 (continued)

REQUIREMENTS consistent with a heat balance when < 25% RTP. At low power levels, a high degree of accuracy is unnecessary because of the large, inherent margin to thermal limits (MCPR, APLHGR, and LHGR). At 25% RTP, the Surveillance is required to have been satisfactorily performed within the last 7 days, in accordance with SR 3.0.2. A Note is provided which allows an increase in THERMAL POWER above 25% if the 7 day Frequency is not met per SR 3.0.2. In this event, the SR must be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reaching or exceeding 25% RTP. Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.

SR 3.3.1.1.3 The Average Power Range Monitor Flow Biased Neutron Flux-High Function uses the recirculation loop drive flows to vary the trip setpoint. This SR ensures that the total loop drive flow signals from the flow converters used to vary the setpoint is appropriately compared to a calibrated flow signal and, therefore, the APRM Function accurately The Frequency may be based reflects the required setpoint as a function of flow. Each on factors such as operating flow signal from the respective flow converter must be experience, equipment reliability, 100% of the calibrated flow signal. If the flow converter or plant risk, and is controlled under the Surveillance signal is not within the limit, all required APRMs that Frequency Control Program. receive an input from the inoperable flow converter must be declared inoperable.

The Frequency of 7 days is based on engineering judgment, operating experience, and the reliability of this instrumentation.

SR 3.3.1.1.4 and SR 3.3.1.1.8 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required (continued)

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RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.4 and SR 3.3.1.1.8 (continued)

REQUIREMENTS contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

As noted, SR 3.3.1.1.4 is not required to be performed when entering MODE 2 from MODE 1, since testing of the MODE 2 required IRM and APRM Functions cannot be performed in MODE 1 without utilizing jumpers, lifted leads, or movable links. This allows entry into MODE 2 if the 7 day Frequency The Frequency may be based is not met per SR 3.0.2. In this event, the SR must be on factors such as operating experience, equipment reliability, performed within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering MODE 2 from MODE 1.

or plant risk, and is controlled Twenty four hours is based on operating experience and in under the Surveillance consideration of providing a reasonable time in which to Frequency Control Program. complete the SR.

A Frequency of 7 days for SR 3.3.1.1.4 provides an acceptable level of system average unavailability over the Frequency interval and is based on reliability analysis (Ref. 13). The Frequency of 31 days for SR 3.3.1.1.8 is acceptable based on engineering judgment, operating experience, and the reliability of this instrumentation.

SR 3.3.1.1.5 A functional test of each automatic scram contactor is performed to ensure that each automatic RPS logic channel will perform the intended function. There are four RPS channel test switches, one associated with each of the four automatic trip channels (A1, A2, B1, and B2). These test switches allow the operator to test the OPERABILITY of the individual trip logic channel automatic scram contactors as an alternative to using an automatic scram function trip.

This is accomplished by placing the RPS channel test switch in the test position, which will input a trip signal into the associated RPS logic channel. The RPS channel test switches are not specifically credited in the accident analysis. The Manual Scram Functions are not configured the same as the generic model used in Reference 13. However, Reference 13 concluded that the Surveillance Frequency (continued)

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RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.5 (continued)

REQUIREMENTS extensions for RPS Functions were not affected by the The Frequency may be based difference in configuration since each automatic RPS logic on factors such as operating experience, equipment reliability, channel has a test switch which is functionally the same as or plant risk, and is controlled the manual scram switches in the generic model. As such, a under the Surveillance functional test of each RPS automatic scram contactor using Frequency Control Program. either its associated test switch or by test of any of the associated automatic RPS Functions is required to be performed once every 7 days. The Frequency of 7 days is based on the reliability analysis of Reference 13.

SR 3.3.1.1.6 and SR 3.3.1.1.7 These Surveillances are established to ensure that no gaps in neutron flux indication exist from subcritical to power operation for monitoring core reactivity status.

The overlap between SRMs and IRMs is required to be demonstrated to ensure that reactor power will not be increased into a neutron flux region without adequate indication. This is required prior to fully withdrawing SRMs since indication is being transitioned from the SRMs to the IRMs.

The overlap between IRMs and APRMs is of concern when reducing power into the IRM range. On power increases, the system design will prevent further increases (by initiating a rod block) if adequate overlap is not maintained. The IRM/APRM and SRM/IRM overlaps are acceptable if a 1/2 decade overlap exists.

As noted, SR 3.3.1.1.7 is only required to be met during entry into MODE 2 from MODE 1. That is, after the overlap requirement has been met and indication has transitioned to the IRMs, maintaining overlap is not required (APRMs may be reading downscale once in MODE 2).

If overlap for a group of channels is not demonstrated (e.g., IRM/APRM overlap), the reason for the failure of the Surveillance should be determined and the appropriate channel(s) declared inoperable. Only those appropriate channels that are required in the current MODE or condition should be declared inoperable.

(continued)

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RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.6 and SR 3.3.1.1.7 (continued)

REQUIREMENTS A Frequency of 7 days is reasonable based on engineering judgment and the reliability of the IRMs and APRMs.

SR 3.3.1.1.9 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 2000 effective full power hours (EFPH) Frequency is based on operating experience with LPRM sensitivity changes.

The Frequency may be based SR 3.3.1.1.10 and SR 3.3.1.1.15 on factors such as operating experience, equipment reliability, A CHANNEL FUNCTIONAL TEST is performed on each required or plant risk, and is controlled channel to ensure that the channel will perform the intended under the Surveillance Frequency Control Program. function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The 92 day Frequency of SR 3.3.1.1.10 is based on the reliability analysis of Reference 13. The 24 month Frequency of SR 3.3.1.1.15 is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency.

(continued)

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RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.11 REQUIREMENTS (continued) Calibration of trip units provides a check of the actual trip setpoints. The channel must be declared inoperable if the trip setting is discovered to be less conservative than the Allowable Value specified in Table 3.3.1.1-1. If the trip setting is discovered to be less conservative than The Frequency may be based accounted for in the appropriate setpoint methodology, but on factors such as operating is not beyond the Allowable Value, the channel performance experience, equipment reliability, or plant risk, and is controlled is still within the requirements of the plant safety under the Surveillance analysis. Under these conditions, the setpoint must be Frequency Control Program. readjusted to be equal to or more conservative than accounted for in the appropriate setpoint methodology.

The Frequency of 92 days is based on the reliability analysis of Reference 13.

SR 3.3.1.1.12, 3.3.1.1.14, and SR 3.3.1.1.16 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies that the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

Note 1 to SR 3.3.1.1.14 and SR 3.3.1.1.16 states that neutron detectors are excluded from CHANNEL CALIBRATION because they are passive devices, with minimal drift, and because of the difficulty of simulating a meaningful signal.

For the APRMs, changes in neutron detector sensitivity are compensated for by performing the 7 day calorimetric calibration (SR 3.3.1.1.2) and the 2000 EFPH LPRM calibration against the TIPs (SR 3.3.1.1.9). A second Note is provided that requires the APRM and IRM SRs to be performed within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of entering MODE 2 from MODE 1.

Testing of the MODE 2 APRM and IRM Functions cannot be performed in MODE 1 without utilizing jumpers, lifted leads, or movable links. This Note allows entry into MODE 2 from MODE 1 if the associated Frequency is not met per SR 3.0.2.

Twenty four hours is based on operating experience and in consideration of providing a reasonable time in which to (continued)

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RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.12, 3.3.1.1.14, and SR 3.3.1.1.16 (continued)

REQUIREMENTS complete the SR. Note 3 to SR 3.3.1.1.14 states that for Function 2.b, this SR is not required for the flow portion of these channels. This allowance is consistent with the The Frequency may be based plant specific setpoint methodology. This portion of the on factors such as operating Function 2.b channels must be calibrated in accordance with experience, equipment reliability, SR 3.3.1.1.16.

or plant risk, and is controlled under the Surveillance The Frequency of SR 3.3.1.1.12 is based upon the assumption Frequency Control Program. of a 92 day calibration interval in determination of the magnitude of equipment drift in the setpoint analysis. The Frequency of SR 3.3.1.1.14 is based upon the assumption of a 184 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis. The Frequency of SR 3.3.1.1.16 is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

SR 3.3.1.1.13 This SR ensures that scrams initiated from the Turbine Stop ValveClosure and Turbine Control Valve Fast Closure, Trip Oil PressureLow Functions will not be inadvertently bypassed when THERMAL POWER is > 38.5% RTP. This involves calibration of the bypass channels. Adequate margins for the instrument setpoint methodologies are incorporated into the actual setpoint. Because main turbine bypass flow can affect this setpoint nonconservatively (THERMAL POWER is derived from turbine first stage pressure), the main turbine bypass valves must remain closed during an in-service calibration at THERMAL POWER > 38.5%, if performing the calibration using actual turbine first stage pressure, to ensure that the calibration remains valid.

If any bypass channels setpoint is nonconservative (i.e.,

the Functions are bypassed at > 38.5% RTP, either due to open main turbine bypass valve(s) Or other reasons), then the affected Turbine Stop ValveClosure and Turbine Control Valve Fast Closure, Trip Oil PressureLow Functions are considered inoperable. Alternatively, the bypass channel can be placed in the conservative condition (nonbypass).

(continued)

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RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.13 (continued)

REQUIREMENTS If placed in the nonbypass condition, this SR is met and the channel is considered OPERABLE. The Frequency of 92 days is based on engineering judgment and reliability of the components.

SR 3.3.1.1.17 The LOGIC SYSTEM FUNCTIONAL TEST (LSFT) demonstrates the OPERABILITY of the required trip logic for a specific channel. The functional testing of control rods (LCO 3.1.3, The Frequency may be based "Control Rod Operability"), and SDV vent and drain valves on factors such as operating experience, equipment reliability, (LCO 3.1.8, "Scram Discharge Volume (SDV) Vent and Drain or plant risk, and is controlled Valves"), overlaps this Surveillance to provide complete under the Surveillance testing of the assumed safety function.

Frequency Control Program.

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency.

SR 3.3.1.1.18 This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis. This test may be performed in one measurement or in overlapping segments, with verification that all components are tested. The RPS RESPONSE TIME acceptance criteria are included in Reference 14.

As noted (Note 1), neutron detectors are excluded from RPS RESPONSE TIME testing because the principles of detector operation virtually ensure an instantaneous response time.

RPS RESPONSE TIME tests are conducted on a 24 month STAGGERED TEST BASIS. Note 2 requires STAGGERED TEST BASIS Frequency to be determined based on 4 channels per trip system, in lieu of the 8 channels specified in Table 3.3.1.1-1 for the MSIV Closure Function. This Frequency is (continued)

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RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.18 (continued)

REQUIREMENTS based on the logic interrelationships of the various channels required to produce an RPS scram signal. The 24 month Frequency is consistent with the typical industry refueling cycle and is based upon plant operating experience, which shows that random failures of instrumentation components causing serious response time degradation, but not channel failure, are infrequent occurrences.

REFERENCES 1. UFSAR, Section 7.2.

2. UFSAR, Section 5.2.2.2.3.

3. UFSAR, Section 6.2.1.3.2.

4. UFSAR, Chapter 15.

5. UFSAR, Section 15.4.1.

6. NEDO-23842, "Continuous Control Rod Withdrawal in the Startup Range," April 18, 1978.

7. UFSAR, Section 15.4.10.

8. UFSAR, Section 15.6.5.

9. UFSAR, Section 15.2.5.

10. P. Check (NRC) letter to G. Lainas (NRC), "BWR Scram Discharge System Safety Evaluation," December 1, 1980.

11. UFSAR, Section 15.2.3.

12. UFSAR, Section 15.2.2.

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

March 1988.

14. Technical Requirements Manual.

15. UFSAR, Section 15.2.2.1.3.

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SRM Instrumentation B 3.3.1.2 BASES SURVEILLANCE SR 3.3.1.2.1 and SR 3.3.1.2.3 (continued)

REQUIREMENTS CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on another channel. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious.

A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

The Frequency may be based on factors such as operating experience, equipment reliability, Agreement criteria are determined by the plant staff based or plant risk, and is controlled on a combination of the channel instrument uncertainties, under the Surveillance including indication and readability. If a channel is Frequency Control Program. outside the criteria, it may be an indication that the instrument has drifted outside its limit.

The Frequency of once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for SR 3.3.1.2.1 is based on operating experience that demonstrates channel failure is rare. While in MODES 3 and 4, reactivity changes are not expected; therefore, the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is relaxed to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for SR 3.3.1.2.3. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.

SR 3.3.1.2.2 To provide adequate coverage of potential reactivity changes in the core, one SRM is required to be OPERABLE in the quadrant where CORE ALTERATIONS are being performed, and the other OPERABLE SRM must be in an adjacent quadrant containing fuel. Note 1 states that the SR is required to be met only during CORE ALTERATIONS. It is not required to be met at other times in MODE 5 since core reactivity changes are not occurring. This Surveillance consists of a review of plant logs to ensure that SRMs required to be OPERABLE for given CORE ALTERATIONS are, in fact, OPERABLE.

In the event that only one SRM is required to be OPERABLE, per Table 3.3.1.2-1, footnote (b), only the a. portion of (continued)

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SRM Instrumentation B 3.3.1.2 BASES SURVEILLANCE SR 3.3.1.2.2 (continued)

REQUIREMENTS this SR is effectively required. Note 2 clarifies that more than one of the three requirements can be met by the same OPERABLE SRM. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is based upon operating experience and supplements operational controls over refueling activities that include steps to ensure that the SRMs required by the LCO are in the proper quadrant.

SR 3.3.1.2.4 This Surveillance consists of a verification of the SRM instrument readout to ensure that the SRM reading is greater than a specified minimum count rate with the detector full The Frequency may be based in, which ensures that the detectors are indicating count on factors such as operating rates indicative of neutron flux levels within the core.

experience, equipment reliability, With few fuel assemblies loaded, the SRMs will not have a or plant risk, and is controlled high enough count rate to satisfy the SR. Therefore, under the Surveillance allowances are made for loading sufficient "source" Frequency Control Program. material, in the form of irradiated fuel assemblies, to establish the minimum count rate.

To accomplish this, the SR is modified by a Note that states that the count rate is not required to be met on an SRM that has less than or equal to four fuel assemblies adjacent to the SRM and no other fuel assemblies are in the associated core quadrant. With four or less fuel assemblies loaded around each SRM and no other fuel assemblies in the associated core quadrant, even with a control rod withdrawn, the configuration will not be critical. When movable detectors are being used, detector location must be selected such that each group of fuel assemblies is separated by at least two fuel cells from any other fuel assemblies.

The Frequency is based upon channel redundancy and other information available in the control room, and ensures that the required channels are frequently monitored while core reactivity changes are occurring. When no reactivity changes are in progress, the Frequency is relaxed from 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

(continued)

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SRM Instrumentation B 3.3.1.2 BASES SURVEILLANCE SR 3.3.1.2.5 and SR 3.3.1.2.6 REQUIREMENTS (continued) Performance of a CHANNEL FUNCTIONAL TEST demonstrates the associated channel will function properly. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is The Frequency may be based acceptable because all of the other required contacts of the on factors such as operating relay are verified by other Technical Specifications and experience, equipment reliability, or plant risk, and is controlled non-Technical Specifications tests at least once per under the Surveillance refueling interval with applicable extensions. SR 3.3.1.2.5 Frequency Control Program. is required in MODE 5, and the 7 day Frequency ensures that the channels are OPERABLE while core reactivity changes could be in progress. This Frequency is reasonable, based on operating experience and on other Surveillances (such as a CHANNEL CHECK), that ensure proper functioning between CHANNEL FUNCTIONAL TESTS.

SR 3.3.1.2.6 is required to be met in MODE 2 with IRMs on Range 2 or below, and in MODES 3 and 4. Since core reactivity changes do not normally take place in MODES 3 and 4 and core reactivity changes are due only to control rod movement in MODE 2, the Frequency is extended from 7 days to 31 days. The 31 day Frequency is based on operating experience and on other Surveillances (such as CHANNEL CHECK) that ensure proper functioning between CHANNEL FUNCTIONAL TESTS.

Verification of the signal to noise ratio also ensures that the detectors are inserted to an acceptable operating level.

In a fully withdrawn condition, the detectors are sufficiently removed from the fueled region of the core to essentially eliminate neutrons from reaching the detector.

Any count rate obtained while the detectors are fully withdrawn is assumed to be "noise" only.

With few fuel assemblies loaded, the SRMs will not have a high enough count rate to determine the signal to noise ratio. Therefore, allowances are made for loading sufficient "source" material, in the form of irradiated fuel assemblies, to establish the conditions necessary to determine the signal to noise ratio. To accomplish this, SR 3.3.1.2.5 is modified by a Note that states that the (continued)

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SRM Instrumentation B 3.3.1.2 BASES SURVEILLANCE SR 3.3.1.2.5 and SR 3.3.1.2.6 (continued)

REQUIREMENTS determination of signal to noise ratio is not required to be met on an SRM that has less than or equal to four fuel assemblies adjacent to the SRM and no other fuel assemblies are in the associated core quadrant. With four or less fuel assemblies loaded around each SRM and no other fuel assemblies in the associated quadrant, even with a control rod withdrawn the configuration will not be critical.

The Note to SR 3.3.1.2.6 allows the Surveillance to be delayed until entry into the specified condition of the Applicability (THERMAL POWER decreased to IRM Range 2 or below). The SR must be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after IRMs are on Range 2 or below. The allowance to enter the Applicability with the 31 day Frequency not met is reasonable, based on the limited time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowed after entering the Applicability and the inability to perform the Surveillance while at higher power levels.

Although the Surveillance could be performed while on IRM Range 3, the plant would not be expected to maintain steady state operation at this power level. In this event, the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is reasonable, based on the SRMs being otherwise verified to be OPERABLE (i.e., satisfactorily performing the CHANNEL CHECK) and the time required to perform the Surveillances.

The Frequency may be based on factors such as operating experience, equipment reliability, SR 3.3.1.2.7 or plant risk, and is controlled under the Surveillance Frequency Control Program. Performance of a CHANNEL CALIBRATION at a Frequency of 24 months verifies the performance of the SRM detectors and associated circuitry. The Frequency considers the plant conditions required to perform the test, the ease of performing the test, and the likelihood of a change in the system or component status. The neutron detectors are excluded from the CHANNEL CALIBRATION (Note 1) because they cannot readily be adjusted. The detectors are fission chambers that are designed to have a relatively constant sensitivity over the range and with an accuracy specified for a fixed useful life.

(continued)

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SRM Instrumentation B 3.3.1.2 BASES SURVEILLANCE SR 3.3.1.2.7 (continued)

REQUIREMENTS Note 2 to SR 3.3.1.2.6 allows the Surveillance to be delayed until entry into the specified condition of the Applicability. The SR must be performed in MODE 2 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of entering MODE 2 with IRMs on Range 2 or below. The allowance to enter the Applicability with the 24 month Frequency not met is reasonable, based on the limited time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowed after entering the Applicability and the inability to perform the Surveillance while at higher power levels. Although the Surveillance could be performed while on IRM Range 3, the plant would not be expected to maintain steady state operation at this power level. In this event, the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is reasonable, based on the SRMs being otherwise verified to be OPERABLE (i.e., satisfactorily performing the CHANNEL CHECK) and the time required to perform the Surveillances.

REFERENCES None.

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OPRM Instrumentation B 3.3.1.3 BASES SURVEILLANCE This Note is based on the RPS reliability analysis (Ref. 8)

REQUIREMENTS assumption of the average time required to perform channel (continued) surveillance. That analysis demonstrated that the 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the RPS will trip when necessary.

SR 3.3.1.3.1 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function.

A Frequency of 184 days provides an acceptable level of system average unavailability over the Frequency interval and is based on the reliability analysis (Ref. 6).

The Frequency may be based on factors such as operating SR 3.3.1.3.2 experience, equipment reliability, or plant risk, and is controlled under the Surveillance LPRM gain settings are determined from the local flux Frequency Control Program. profiles measured by the Traversing Incore Probe (TIP)

System. This establishes the relative local flux profile for appropriate representative input to the OPRM System.

The 2000 effective full power hours (EFPH) Frequency is based on operating experience with LPRM sensitivity changes.

SR 3.3.1.3.3 The CHANNEL CALIBRATION is a complete check of the instrument loop. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations, consistent with the plant specific setpoint methodology.

Calibration of the channel provides a check of the internal reference voltage and the internal processor clock frequency. It also compares the desired trip setpoint with those in the processor memory. Since the OPRM is a digital system, the internal reference voltage and processor clock frequency are, in turn, used to automatically calibrate the internal analog to digital converters. The nominal setpoints for the period based detection algorithm are specified in the COLR. As noted, neutron detectors are (continued)

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OPRM Instrumentation B 3.3.1.3 BASES SURVEILLANCE SR 3.3.1.3.3 (continued)

REQUIREMENTS excluded from CHANNEL CALIBRATION because of difficulty of simulating a meaningful signal. Changes in neutron detector sensitivity are compensated for by performing the 2000 effective full power hour (EFPH) calibration against the TIPs (SR 3.3.1.1.9). SR 3.3.1.1.9 thus also ensures the operability of the OPRM instrumentation.

The nominal setpoints for the OPRM trip function for the period based detection algorithm (PBDA) are specified in the Core Operating Limits Report. The PBDA trip setpoints are the number of confirmation counts required to permit a trip signal and the peak to average amplitude required to generate a trip signal.

The Frequency of 24 months is based upon the assumption of the magnitude of equipment drift provided by the equipment supplier (Ref. 6).

SR 3.3.1.3.4 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The functional testing of control rods, in LCO 3.1.3, "Control Rod OPERABILITY," and scram discharge volume The Frequency may be based (SDV) vent and drain valves, in LCO 3.1.8, "Scram Discharge on factors such as operating Volume (SDV) Vent and Drain Valves," overlaps this experience, equipment reliability, Surveillance to provide complete testing of the assumed or plant risk, and is controlled under the Surveillance safety function. The OPRM self-test function may be Frequency Control Program. utilized to perform this testing for those components that it is designated to monitor.

The 24 month Frequency is based on engineering judgement and reliability of the components. Operating experience has shown these components usually pass the surveillance when performed at the 24 month Frequency.

SR 3.3.1.3.5 This SR ensures that trips initiated from the OPRM System will not be bypassed (i.e., fail to enable) when THERMAL POWER is 25% RTP and recirculation drive flow is < 60% of rated recirculation drive flow. This normally involves (continued)

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OPRM Instrumentation B 3.3.1.3 BASES SURVEILLANCE SR 3.3.1.3.5 (continued)

REQUIREMENTS calibration of the bypass channels. The 25% RTP value is the plant specific value for the enable region, as described in Reference 9. The value has been conservatively rounded to coincide with the LCO Applicability.

These values have been conservatively selected so that specific, additional uncertainty allowances need not be applied. Specifically, for THERMAL POWER, the Average Power Range Monitor (APRM) establishes the reference signal to enable the OPRM system at 25% RTP. Thus, the nominal setpoints corresponding to the values listed above (25% of RTP and 60% of rated recirculation drive flow) will be used to establish the enabled region of the OPRM System trips.

(References 1, 2, 5, 9, and 11)

If any bypass channel setpoint is nonconservative (i.e., the OPRM module is bypassed at 25% RTP and < 60% of rated recirculation drive flow), then the affected OPRM module is considered inoperable. Alternately, the bypass channel can be placed in the conservative condition (nonbypass). If placed in the nonbypass condition, this SR is met and the module is considered OPERABLE.

The Frequency of 24 months is based on engineering judgment and reliability of the components.

SR 3.3.1.3.6 This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis. The OPRM self-test function may be The Frequency may be based utilized to perform this testing for those components it is on factors such as operating designed to monitor. The RPS RESPONSE TIME acceptance experience, equipment reliability, or plant risk, and is controlled criteria are included in Reference 10.

under the Surveillance Frequency Control Program. As noted, neutron detectors are excluded from RPS RESPONSE TIME testing because the principles of detector operation virtually ensure an instantaneous response time. RPS RESPONSE TIME tests are conducted on a 24 month STAGGERED TEST BASES. This frequency is based upon operating experience, which shows that random failures of instrumentation components causing serious time degradation, but not channel failure, are infrequent.

(continued)

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Control Rod Block Instrumentation B 3.3.2.1 BASES APPLICABLE 1. Rod Block Monitor (continued)

SAFETY ANALYSES, LCO, and from the safety analysis. The Allowable Values are derived APPLICABILITY from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined accounting for the remaining instrument errors (e.g., drift). The trip setpoints and Allowable Values determined in this manner provide adequate protection because instrument uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for and appropriately applied for the instrumentation.

The RBM is assumed to mitigate the consequences of an RWE event when operating 30% RTP and a non-peripheral control rod is selected. Below this power level, or if a peripheral control rod is selected, the consequences of an RWE event will not exceed the MCPR SL and, therefore, the RBM is not required to be OPERABLE (Ref. 3).

2. Rod Worth Minimizer The RWM enforces the analyzed rod position sequence to ensure that the initial conditions of the CRDA analysis are not violated. The analytical methods and assumptions used 13 in evaluating the CRDA are summarized in References 4, 5, 6, 7, 8, and 14. The analyzed rod position sequence requires that control rods be moved in groups, with all control rods assigned to a specific group required to be within specified banked positions. Requirements that the control rod sequence is in compliance with the analyzed rod position sequence are specified in LCO 3.1.6, "Rod Pattern Control."

12 When performing a shutdown of the plant, an optional control rod sequence (Ref. 13) may be used if the coupling of each withdrawn control rod has been confirmed. The rods may be inserted without the need to stop at intermediate positions.

When using the Reference 13 control rod insertion sequence for shutdown, the rod worth minimizer may be reprogrammed to enforce the requirements of the improved control rod insertion process.

(continued)

Quad Cities 1 and 2 B 3.3.2.1-4 Revision 28

Control Rod Block Instrumentation B 3.3.2.1 BASES APPLICABLE 2. Rod Worth Minimizer (continued)

SAFETY ANALYSES, LCO, and The RWM Function satisfies Criterion 3 of APPLICABILITY 10 CFR 50.36(c)(2)(ii).

Since the RWM is a system designed to act as a backup to operator control of the rod sequences, only one channel of the RWM is available and required to be OPERABLE (Ref. 9).

Special circumstances provided for in the Required Action of LCO 3.1.3, "Control Rod OPERABILITY," and LCO 3.1.6 may necessitate bypassing the RWM to allow continued operation with inoperable control rods, or to allow correction of a control rod pattern not in compliance with the analyzed rod position sequence. The RWM may be bypassed as required by these conditions, but then it must be considered inoperable and the Required Actions of this LCO followed.

Compliance with the analyzed rod position sequence, and therefore OPERABILITY of the RWM, is required in MODES 1 and 2 when THERMAL POWER is 10% RTP. When THERMAL POWER is > 10% RTP, there is no possible control rod configuration that results in a control rod worth that could exceed the 280 cal/gm fuel design limit during a CRDA (Refs. 9, 10, and 13 14). In MODES 3 and 4, all control rods are required to be inserted into the core; therefore, a CRDA cannot occur. In MODE 5, since only a single control rod can be withdrawn from a core cell containing fuel assemblies, adequate SDM ensures that the consequences of a CRDA are acceptable, since the reactor will be subcritical.

3. Reactor Mode SwitchShutdown Position During MODES 3 and 4, and during MODE 5 when the reactor mode switch is in the shutdown position, the core is assumed to be subcritical; therefore, no positive reactivity insertion events are analyzed. The Reactor Mode Switch-Shutdown Position control rod withdrawal block ensures that the reactor remains subcritical by blocking control rod withdrawal, thereby preserving the assumptions of the safety analysis.

The Reactor Mode SwitchShutdown Position Function satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).

(continued)

Quad Cities 1 and 2 B 3.3.2.1-5 Revision 28

Control Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE applicable Condition entered and Required Actions taken.

REQUIREMENTS This Note is based on the reliability analysis (Ref. 11)

(continued) assumption of the average time required to perform channel Surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that a control rod block will be initiated when necessary.

SR 3.3.2.1.1 A CHANNEL FUNCTIONAL TEST is performed for each RBM channel to ensure that the entire channel will perform the intended function. It includes the Reactor Manual Control "Relay Select Marix" System input. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by The Frequency may be based other Technical Specifications and non-Technical on factors such as operating Specifications tests at least once per refueling interval experience, equipment reliability, or plant risk, and is controlled with applicable extensions.

under the Surveillance Frequency Control Program. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology. The Frequency of 92 days is based on reliability analyses (Ref. 12).

SR 3.3.2.1.2 and SR 3.3.2.1.3 A CHANNEL FUNCTIONAL TEST is performed for the RWM to ensure that the entire system will perform the intended function.

A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. The CHANNEL FUNCTIONAL TEST for the RWM is performed by attempting to withdraw a control rod not in compliance with the prescribed sequence and verifying a control rod block occurs and by (continued)

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Control Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE SR 3.3.2.1.2 and SR 3.3.2.1.3 (continued)

REQUIREMENTS attempting to select a control rod not in compliance with the prescribed sequence and verifying a selection error occurs. As noted in the SRs, SR 3.3.2.1.2 is not required to be performed until 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after any control rod is withdrawn at 10% RTP in MODE 2, and SR 3.3.2.1.3 is not required to be performed until 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after THERMAL POWER is 10% RTP in MODE 1. The Note to SR 3.3.2.1.2 allows entry into MODE 2 on a startup and entry in MODE 2 concurrent with a power reduction to 10% RTP during a shutdown to perform The Frequency may be based the required Surveillance if the 92 day Frequency is not met on factors such as operating per SR 3.0.2. The Note to SR 3.3.2.1.3 allows a THERMAL experience, equipment reliability, or plant risk, and is controlled POWER reduction to 10% RTP in MODE 1 to perform the under the Surveillance required Surveillance if the 92 day Frequency is not met per Frequency Control Program. SR 3.0.2. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months allowance is based on operating experience and in consideration of providing a reasonable time in which to complete the SRs. Operating experience has shown that these components usually pass the Surveillance when performed at the 92 day Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.3.2.1.4 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

As noted, neutron detectors are excluded from the CHANNEL CALIBRATION because they are passive devices, with minimal drift, and because of the difficulty of simulating a meaningful signal. Neutron detectors are adequately tested in SR 3.3.1.1.2 and SR 3.3.1.1.8.

The Frequency is based upon the assumption of a 92 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

(continued)

Quad Cities 1 and 2 B 3.3.2.1-10 Revision 21

Control Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE SR 3.3.2.1.5 REQUIREMENTS (continued) The RBM is automatically bypassed when power is below a specified value or if a peripheral control rod is selected.

The power level is determined from the APRM signals input to each RBM channel. The automatic bypass setpoint must be verified periodically to be < 30% RTP. In addition, it must also be verified that the RBM is not bypassed when a control rod that is not a peripheral control rod is selected (only one non-peripheral control rod is required to be verified).

If any bypass setpoint is nonconservative, then the affected RBM channel is considered inoperable. Alternatively, the APRM channel can be placed in the conservative condition to The Frequency may be based enable the RBM. If placed in this condition, the SR is met on factors such as operating and the RBM channel is not considered inoperable. As noted, experience, equipment reliability, neutron detectors are excluded from the Surveillance because or plant risk, and is controlled under the Surveillance they are passive devices, with minimal drift, and because of Frequency Control Program. the difficulty of simulating a meaningful signal. Neutron detectors are adequately tested in SR 3.3.1.1.2 and SR 3.3.1.1.8. The 92 day Frequency is based on the actual trip setpoint methodology utilized for these channels.

SR 3.3.2.1.6 The RWM is automatically bypassed when power is above a specified value. The power level is determined from feedwater flow and steam flow signals. The automatic bypass setpoint must be verified periodically to be > 10% RTP. If the RWM low power setpoint is nonconservative, then the RWM is considered inoperable. Alternately, the low power setpoint channel can be placed in the conservative condition (nonbypass). If placed in the nonbypassed condition, the SR is met and the RWM is not considered inoperable. The Frequency is based on the trip setpoint methodology utilized for the low power setpoint channel.

SR 3.3.2.1.7 A CHANNEL FUNCTIONAL TEST is performed for the Reactor Mode SwitchShutdown Position Function to ensure that the entire channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be (continued)

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Control Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE SR 3.3.2.1.7 (continued)

REQUIREMENTS performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. The CHANNEL FUNCTIONAL TEST for the Reactor Mode SwitchShutdown Position Function is performed by attempting to withdraw any control rod with the reactor mode switch in the shutdown position and verifying a control rod block occurs.

As noted in the SR, the Surveillance is not required to be performed until 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after the reactor mode switch is in the shutdown position, since testing of this interlock with The Frequency may be based the reactor mode switch in any other position cannot be on factors such as operating performed without using jumpers, lifted leads, or movable experience, equipment reliability, or plant risk, and is controlled links. This allows entry into MODES 3 and 4 if the 24 month under the Surveillance Frequency is not met per SR 3.0.2. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months allowance is Frequency Control Program. based on operating experience and in consideration of providing a reasonable time in which to complete the SRs.

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency.

SR 3.3.2.1.8 The RWM will only enforce the proper control rod sequence if the rod sequence is properly input into the RWM computer.

This SR ensures that the proper sequence is loaded into the RWM so that it can perform its intended function. The Surveillance is performed once prior to declaring RWM OPERABLE following loading of sequence into RWM, since this is when rod sequence input errors are possible.

(continued)

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Control Rod Block Instrumentation B 3.3.2.1 BASES REFERENCES 9. NRC SER, "Acceptance of Referencing of Licensing (continued) Topical Report NEDE-24011-P-A," "General Electric Standard Application for Reactor Fuel, Revision 8, Amendment 17," December 27, 1987.

10. "Modifications to the Requirements for Control Rod Drop Accident Mitigating Systems," BWR Owners' Group, July 1986.

11. GENE-770-06-1-A, "Addendum to Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," December 1992.

12. NEDC-30851-P-A, Supplement 1, "Technical Specification Improvement Analysis for BWR Control Rod Block Instrumentation," October 1988.

12

13. NEDO-33091-A, Revision 2, "Improved BPWS Control Rod Insertion Process," July 2004.

13

14. CENPD-284-P-A, "Control Rod Drop Accident Analysis Methodology for Boiling Water Reactors: Summary and Qualification."

Quad Cities 1 and 2 B 3.3.2.1-14 Revision 28

Feedwater System and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 BASES SURVEILLANCE not significantly reduce the probability that the Feedwater REQUIREMENTS pumps and main turbine will trip when necessary.

(continued)

SR 3.3.2.2.1 Performance of the CHANNEL CHECK once every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between instrument channels could be an indication of excessive instrument drift in one of the channels, or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

The Frequency may be based on factors such as operating Agreement criteria are determined by the plant staff based experience, equipment reliability, or plant risk, and is controlled on a combination of the channel instrument uncertainties, under the Surveillance including indication and readability. If a channel is Frequency Control Program. outside the criteria, it may be an indication that the instrument has drifted outside its limits.

The Frequency is based on operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channel status during normal operational use of the displays associated with the channels required by the LCO.

SR 3.3.2.2.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable (continued)

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Feedwater System and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 BASES SURVEILLANCE SR 3.3.2.2.2 (continued)

REQUIREMENTS extensions. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Frequency of 92 days is based on operating experience.

SR 3.3.2.2.3 Calibration of trip units provides a check of the actual trip setpoints. The channel must be declared inoperable if the trip setting is discovered to be less conservative than the Allowable Value. If the trip setting is discovered to The Frequency may be based on factors such as operating be less conservative than accounted for in the appropriate experience, equipment reliability, setpoint methodology, but is not beyond the Allowable Value, or plant risk, and is controlled the channel performance is still within the requirements of under the Surveillance the plant safety analysis. Under these conditions, the Frequency Control Program. setpoint must be readjusted to be equal to or more conservative than that accounted for in the appropriate setpoint methodology.

SR 3.3.2.2.4 CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

The Frequency is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

SR 3.3.2.2.5 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The system functional test of the feedwater pump breakers and main turbine stop valves is included as part of (continued)

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Feedwater System and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 BASES SURVEILLANCE SR 3.3.2.2.5 (continued)

REQUIREMENTS The Frequency may be based this Surveillance and overlaps the LOGIC SYSTEM FUNCTIONAL on factors such as operating TEST to provide complete testing of the assumed safety experience, equipment reliability, function. Therefore, if a main turbine stop valve or or plant risk, and is controlled under the Surveillance feedwater pump breaker is incapable of operating, the Frequency Control Program. associated instrumentation would also be inoperable. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency.

REFERENCES 1. UFSAR, Section 15.1.2.

2. GENE-770-06-1-A, "Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications,"

December 1992.

Quad Cities 1 and 2 B 3.3.2.2-8 Revision 32

PAM Instrumentation B 3.3.3.1 BASES ACTIONS F.1 (continued)

Since alternate means of monitoring drywell radiation have been developed and tested, the Required Action is not to shut down the plant, but rather to follow the directions of Specification 5.6.6. These alternate means may be temporarily installed if the normal PAM channel cannot be restored to OPERABLE status within the allotted time. The report provided to the NRC should discuss the alternate means used, describe the degree to which the alternate means are equivalent to the installed PAM channels, justify the areas in which they are not equivalent, and provide a schedule for restoring the normal PAM channels.

SURVEILLANCE As noted at the beginning of the SRs, the following SRs REQUIREMENTS apply to each PAM instrumentation Function in Table 3.3.3.1-1.

The Surveillances are modified by a second Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , provided the other required channel in the associated Function is OPERABLE. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken.

The 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance is acceptable since it does not significantly reduce the probability of properly monitoring post-accident parameters, when necessary.

SR 3.3.3.1.1 Performance of the CHANNEL CHECK once every 31 days ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel against a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect (continued)

Quad Cities 1 and 2 B 3.3.3.1-10 Revision 25

PAM Instrumentation B 3.3.3.1 BASES SURVEILLANCE SR 3.3.3.1.1 (continued)

REQUIREMENTS gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION. The high radiation instrumentation should be compared to similar plant instruments located throughout the plant.

The Frequency may be based Agreement criteria are determined by the plant staff, based on factors such as operating on a combination of the channel instrument uncertainties, experience, equipment reliability, including indication and readability. If a channel is or plant risk, and is controlled under the Surveillance outside the criteria, it may be an indication that the Frequency Control Program. sensor or the signal processing equipment has drifted outside its limit.

The Frequency of 31 days is based upon plant operating experience, with regard to channel OPERABILITY and drift, which demonstrates that failure of more than one channel of a given Function in any 31 day interval is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of those displays associated with the channels required by the LCO.

SR 3.3.3.1.2 A CHANNEL CALIBRATION is performed every 24 months for all functions. CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies the channel responds to measured parameter with the necessary range and accuracy. For Function 5, the CHANNEL CALIBRATION shall consist of an electronic calibration of the channel, excluding the detector, for range decades

> 10 R/hour and a one point calibration check of the detector with an installed or portable gamma source for the range decade < 10 R/hour. For Function 6, the CHANNEL CALIBRATION shall consist of verifying that the position indication conforms to actual valve position.

(continued)

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PAM Instrumentation B 3.3.3.1 BASES SURVEILLANCE SR 3.3.3.1.2 (continued)

REQUIREMENTS The 24 month Frequency for CHANNEL CALIBRATION of all other PAM Instrumentation of Table 3.3.3.1-1 is based on operating experience and consistency with the refueling cycles.

REFERENCES 1. Regulatory Guide 1.97, "Instrumentation for Light The Frequency may be based Water Cooled Nuclear Power Plants to Assess Plant and on factors such as operating Environs Conditions During and Following an Accident,"

experience, equipment reliability, Revision 2, December 1980.

or plant risk, and is controlled under the Surveillance Frequency Control Program. 2. NRC letter, T. Ross (NRC) to H.E. Bliss (Commonwealth Edison Company), "Conformance of Post Accident Monitoring Instrumentation at Quad Cities with Regulatory Guide 1.97," dated August 16, 1988.

Quad Cities 1 and 2 B 3.3.3.1-12 Revision 25

ATWS-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE associated Conditions and Required Actions may be delayed REQUIREMENTS for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains (continued) ATWS-RPT trip capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken.

This Note is based on the reliability analysis (Ref. 3) assumption of the average time required to perform channel Surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the recirculation pumps will trip when necessary.

SR 3.3.4.1.1 Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

The Frequency may be based on factors such as operating Agreement criteria are determined by the plant staff based experience, equipment reliability, or plant risk, and is controlled on a combination of the channel instrument uncertainties, under the Surveillance including indication and readability. If a channel is Frequency Control Program. outside the criteria, it may be an indication that the instrument has drifted outside its limit.

The Frequency is based upon operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the required channels of this LCO.

(continued)

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ATWS-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE SR 3.3.4.1.2 REQUIREMENTS (continued) Calibration of trip units provides a check of the actual trip setpoints. The channel must be declared inoperable if the trip setting is discovered to be less conservative than the Allowable Value specified in SR 3.3.4.1.4. If the trip setting is discovered to be less conservative than the The Frequency may be based setting accounted for in the appropriate setpoint on factors such as operating methodology, but is not beyond the Allowable Value, the experience, equipment reliability, channel performance is still within the requirements of the or plant risk, and is controlled under the Surveillance ATWS analysis. Under these conditions, the setpoint must be Frequency Control Program. readjusted to be equal to or more conservative than accounted for in the appropriate setpoint methodology.

The Frequency of 92 days is based on the reliability analysis of Reference 3.

SR 3.3.4.1.3 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Frequency of 92 days is based on the reliability analysis of Reference 3.

SR 3.3.4.1.4 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor, including the time delay relays associated with the Reactor Vessel Water LevelLow Low Function. This test verifies the channel responds to the (continued)

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ATWS-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE SR 3.3.4.1.4 (continued)

REQUIREMENTS measured parameter within the necessary range and accuracy.

CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

The Frequency is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

SR 3.3.4.1.5 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The system functional test of the pump breakers is The Frequency may be based included as part of this Surveillance and overlaps the LOGIC on factors such as operating SYSTEM FUNCTIONAL TEST to provide complete testing of the experience, equipment reliability, assumed safety function. Therefore, if a field breaker on or plant risk, and is controlled under the Surveillance Unit 2, or an ASD feed breaker or ASD emergency stop circuit Frequency Control Program. for Unit 1 is incapable of operating, the associated instrument channel(s) would be inoperable.

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency.

REFERENCES 1. UFSAR, Section 7.8.

2. UFSAR, Section 15.8

3. GENE-770-06-1-A, "Bases for Changes To Surveillance Test Intervals and Allowed Out-of-Service Times For Selected Instrumentation Technical Specifications,"

December 1992.

Quad Cities 1 and 2 B 3.3.4.1-10 Revision 38

ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE The Surveillances are modified by a Note to indicate that REQUIREMENTS when a channel is placed in an inoperable status solely for (continued) performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months as follows: (a) for Functions 3.c, 3.f, and 3.g; and (b) for Functions other than 3.c, 3.f, and 3.g provided the associated Function or redundant Function maintains ECCS initiation capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 4) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the ECCS will initiate when necessary.

SR 3.3.5.1.1 Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations will detect gross channel failure between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK guarantees that undetected outright channel failure is limited to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Agreement criteria are determined by the plant staff, based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.

(continued)

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ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE SR 3.3.5.1.1 (continued)

REQUIREMENTS The Frequency is based upon operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.

SR 3.3.5.1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Frequency of 92 days for SR 3.3.5.1.2 is based on engineering judgement and the reliability of the equipment.

SR 3.3.5.1.3 Calibration of trip units provides a check of the actual trip setpoints. The channel must be declared inoperable if the trip setting is discovered to be less conservative than the Allowable Value specified in Table 3.3.5.1-1. If the trip setting is discovered to be less conservative than accounted for in the appropriate setpoint methodology, but The Frequency may be based is not beyond the Allowable Value, the channel performance on factors such as operating is still within the requirements of the plant safety experience, equipment reliability, or plant risk, and is controlled analyses. Under these conditions, the setpoint must be under the Surveillance readjusted to be equal to or more conservative than the Frequency Control Program. setting accounted for in the appropriate setpoint methodology.

The frequency of 92 days is based on the reliability analysis of Reference 4.

(continued)

Quad Cities 1 and 2 B 3.3.5.1-41 Revision 9

ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE SR 3.3.5.1.4, SR 3.3.5.1.5, and SR 3.3.5.1.6 REQUIREMENTS (continued) A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

The Frequency of SR 3.3.5.1.4 is based upon the assumption of a 92 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis. The Frequency of SR 3.3.5.1.5 is based upon the assumption of a 184 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis. The Frequency of SR 3.3.5.1.6 is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

SR 3.3.5.1.7 The Frequency may be based The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the on factors such as operating OPERABILITY of the required initiation logic for a specific experience, equipment reliability, channel. The system functional testing performed in or plant risk, and is controlled under the Surveillance LCO 3.5.1, LCO 3.5.2, LCO 3.8.1, and LCO 3.8.2 overlaps this Frequency Control Program. Surveillance to provide complete testing of the assumed safety function.

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency.

(continued)

Quad Cities 1 and 2 B 3.3.5.1-42 Revision 9

RCIC System Instrumentation B 3.3.5.2 BASES (continued)

SURVEILLANCE As noted in the beginning of the SRs, the SRs for each RCIC REQUIREMENTS System instrumentation Function are found in the SRs column of Table 3.3.5.2-1.

The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed as follows:

(a) for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for Functions 2 and 5; and (b) for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for Functions 1, 3, and 4, provided the associated Function maintains RCIC initiation capability.

Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 1) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the RCIC will initiate when necessary.

SR 3.3.5.2.1 Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a parameter on other similar channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.

(continued)

Quad Cities 1 and 2 B 3.3.5.2-11 Revision 0

RCIC System Instrumentation B 3.3.5.2 BASES SURVEILLANCE SR 3.3.5.2.1 (continued)

REQUIREMENTS The Frequency is based upon operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.

SR 3.3.5.2.2 Calibration of trip units provides a check of the actual The Frequency may be based trip setpoints. The channel must be declared inoperable if on factors such as operating the trip setting is discovered to be less conservative than experience, equipment reliability, or plant risk, and is controlled the Allowable Value. If the trip setting is discovered to under the Surveillance be less conservative than accounted for in the appropriate Frequency Control Program. setpoint methodology, but is not beyond the Allowable Value, the channel performance is still within the requirements of the plant safety analysis. Under these conditions, the setpoint must be readjusted to be equal to or more conservative than that accounted for in the appropriate setpoint methodology.

SR 3.3.5.2.3 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.

Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The 92 day Frequency of SR 3.3.5.2.3 is based on the reliability of the components.

(continued)

Quad Cities 1 and 2 B 3.3.5.2-12 Revision 9

RCIC System Instrumentation B 3.3.5.2 BASES SURVEILLANCE SR 3.3.5.2.4 REQUIREMENTS (continued) A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

The Frequency of SR 3.3.5.2.4 is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

SR 3.3.5.2.5 The Frequency may be based on factors such as operating The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the experience, equipment reliability, or plant risk, and is controlled OPERABILITY of the required initiation logic for a specific under the Surveillance channel. The system functional testing performed in Frequency Control Program. LCO 3.5.3 overlaps this Surveillance to provide complete testing of the safety function.

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency.

REFERENCES 1. GENE-770-06-2A, "Addendum to Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," December 1992.

Quad Cities 1 and 2 B 3.3.5.2-13 Revision 9

Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS I.1 and I.2 (continued)

If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the associated penetration flow path should be closed. However, if the shutdown cooling function is needed to provide core cooling, these Required Actions allow the penetration flow path to remain unisolated provided action is immediately initiated to restore the channel to OPERABLE status or to isolate the RHR Shutdown Cooling System (i.e., provide alternate decay heat removal capabilities so the penetration flow path can be isolated). Actions must continue until the channel is restored to OPERABLE status or the RHR Shutdown Cooling System is isolated.

SURVEILLANCE As noted at the beginning of the SRs, the SRs for each REQUIREMENTS Primary Containment Isolation instrumentation Function are found in the SRs column of Table 3.3.6.1-1.

The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains isolation capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Refs. 9 and 10) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the PCIVs will isolate the penetration flow path(s) when necessary.

SR 3.3.6.1.1 Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of (continued)

Quad Cities 1 and 2 B 3.3.6.1-25 Revision 23

Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE SR 3.3.6.1.1 (continued)

REQUIREMENTS excessive instrument drift in one of the channels or of something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.

The Frequency is based on operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.

SR 3.3.6.1.2 and SR 3.3.6.1.5 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required The Frequency may be based contacts of the relay are verified by other Technical on factors such as operating Specifications and non-Technical Specifications tests at experience, equipment reliability, or plant risk, and is controlled least once per refueling interval with applicable under the Surveillance extensions. Any setpoint adjustment shall be consistent Frequency Control Program. with the assumptions of the current plant specific setpoint methodology.

The 92 day Frequency of SR 3.3.6.1.2 is based on the reliability analyses described in References 9 and 10. The 24 month Frequency of SR 3.3.6.1.5 is based on engineering judgement and the reliability of the components.

(continued)

Quad Cities 1 and 2 B 3.3.6.1-26 Revision 23

Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE SR 3.3.6.1.3 REQUIREMENTS (continued) Calibration of trip units provides a check of the actual trip setpoints. The channel must be declared inoperable if the trip setting is discovered to be less conservative than the Allowable Value specified in Table 3.3.6.1-1. If the trip setting is discovered to be less conservative than accounted for in the appropriate setpoint methodology, but is not beyond the Allowable Value, the channel performance is still within the requirements of the plant safety analysis. Under these conditions, the setpoint must be readjusted to be equal to or more conservative than that accounted for in the appropriate setpoint methodology.

The Frequency of 92 days is based on the reliability analyses of References 9 and 10.

SR 3.3.6.1.4 and SR 3.3.6.1.6 A CHANNEL CALIBRATION is a complete check of the instrument The Frequency may be based loop and the sensor. This test verifies the channel on factors such as operating responds to the measured parameter within the necessary experience, equipment reliability, range and accuracy. CHANNEL CALIBRATION leaves the channel or plant risk, and is controlled under the Surveillance adjusted to account for instrument drifts between successive Frequency Control Program. calibrations consistent with the plant specific setpoint methodology.

The Frequency of SR 3.3.6.1.4 is based on the assumption of a 92 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis. The Frequency of SR 3.3.6.1.6 is based on the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

SR 3.3.6.1.7 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required isolation logic for a specific channel. The system functional testing performed on PCIVs in LCO 3.6.1.3 overlaps this Surveillance to provide complete testing of the assumed safety function. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant (continued)

Quad Cities 1 and 2 B 3.3.6.1-27 Revision 23

Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE SR 3.3.6.1.7 (continued)

REQUIREMENTS outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency.

REFERENCES 1. UFSAR, Table 6.2-7.

2. 10 CFR 50.62.

3. UFSAR, Section 6.2.

4. UFSAR, Chapter 15.

5. UFSAR, Section 15.6.5.

6. UFSAR, Section 15.1.3.

7. UFSAR, Section 15.6.4.

8. UFSAR, Section 9.3.5.

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

July 1990.

10. NEDC-30851P-A Supplement 2, "Technical Specifications Improvement Analysis for BWR Isolation Instrumentation Common to RPS and ECCS Instrumentation," March 1989.

Quad Cities 1 and 2 B 3.3.6.1-28 Revision 23

Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES SURVEILLANCE SR 3.3.6.2.1 REQUIREMENTS (continued) Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

The Frequency may be based on factors such as operating Agreement criteria are determined by the plant staff based experience, equipment reliability, on a combination of the channel instrument uncertainties, or plant risk, and is controlled under the Surveillance including indication and readability. If a channel is Frequency Control Program. outside the criteria, it may be an indication that the instrument has drifted outside its limit.

The Frequency is based on operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channel status during normal operational use of the displays associated with channels required by the LCO.

SR 3.3.6.2.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

(continued)

Quad Cities 1 and 2 B 3.3.6.2-10 Revision 0

Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES SURVEILLANCE SR 3.3.6.2.2 (continued)

REQUIREMENTS The Frequency of 92 days is based on the reliability analysis of References 3 and 4.

SR 3.3.6.2.3 Calibration of trip units provides a check of the actual trip setpoints. The channel must be declared inoperable if the trip setting is discovered to be less conservative than the Allowable Value specified in Table 3.3.6.2-1. If the trip setting is discovered to be less conservative than The Frequency may be based accounted for in the appropriate setpoint methodology, but on factors such as operating is not beyond the Allowable Value, performance is still experience, equipment reliability, or plant risk, and is controlled within the requirements of the plant safety analysis. Under under the Surveillance these conditions, the setpoint must be readjusted to be Frequency Control Program. equal to or more conservative than accounted for in the appropriate setpoint methodology.

The Frequency of 92 days is based on the reliability analysis of References 3 and 4.

SR 3.3.6.2.4 and SR 3.3.6.2.5 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

The Frequencies of SR 3.3.6.2.4 and SR 3.3.6.2.5 are based on the assumption of a 92 day and a 24 month calibration interval, respectively, in the determination of the magnitude of equipment drift in the setpoint analysis.

(continued)

Quad Cities 1 and 2 B 3.3.6.2-11 Revision 31

Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES SURVEILLANCE SR 3.3.6.2.6 REQUIREMENTS (continued) The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the The Frequency may be based OPERABILITY of the required isolation logic for a specific on factors such as operating channel. The system functional testing performed on SCIVs experience, equipment reliability, and the SGT System in LCO 3.6.4.2 and LCO 3.6.4.3, or plant risk, and is controlled respectively, overlaps this Surveillance to provide complete under the Surveillance testing of the assumed safety function.

Frequency Control Program.

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency.

REFERENCES 1. UFSAR, Section 6.2.3.

2. UFSAR, Section 15.6.5.

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

July 1990.

4. NEDC-30851P-A Supplement 2, "Technical Specifications Improvement Analysis for BWR Isolation Instrumentation Common to RPS and ECCS Instrumentation," March 1989.

5. UFSAR, Section 9.1.4.3.2.

6. NRC Safety Evaluation Report for the Holtec International HI-STORM 100 Storage System (Docket Number 72-1014, Certificate Number 1014, Amendment 2).

Quad Cities 1 and 2 B 3.3.6.2-12 Revision 31

Relief Valve Instrumentation B 3.3.6.3 BASES ACTIONS B.1 (continued)

If the Required Action and associated Completion Time of Condition A is not met, or two or more relief valves are inoperable due to inoperable channels, the relief valves may be incapable of performing their intended relief or low set function. Therefore, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE As noted at the beginning of the SRs, the SRs for each LLS REQUIREMENTS instrumentation Function are located in the SRs column of Table 3.3.6.3-1.

The Frequency may be based on factors such as operating SR 3.3.6.3.1 experience, equipment reliability, or plant risk, and is controlled CHANNEL CALIBRATION is a complete check of the instrument under the Surveillance loop and sensor. This test verifies the channel responds to Frequency Control Program. the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

The Frequency of once every 24 months for SR 3.3.6.3.1 is based on the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

SR 3.3.6.3.2 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required actuation logic for a specified channel. The system functional testing performed in LCO 3.4.3, "Safety and Relief Valves" and LCO 3.6.1.6, "Low Set Relief Valves," overlaps this test to provide complete testing of the assumed safety function.

(continued)

Quad Cities 1 and 2 B 3.3.6.3-5 Revision 0

Relief Valve Instrumentation B 3.3.6.3 BASES SURVEILLANCE SR 3.3.6.3.2 (continued)

REQUIREMENTS The Frequency of once every 24 months for SR 3.3.6.3.2 is based on the need to perform this Surveillance under the The Frequency may be based conditions that apply during a plant outage and the on factors such as operating potential for an unplanned transient if the Surveillance experience, equipment reliability, were performed with the reactor at power. Operating or plant risk, and is controlled experience has shown these components usually pass the under the Surveillance Surveillance when performed at the 24 month Frequency.

Frequency Control Program.

REFERENCES 1. UFSAR, Figure 5.2.2.

2. UFSAR, Section 6.2.1.3.4.

3. UFSAR, Chapter 15.

Quad Cities 1 and 2 B 3.3.6.3-6 Revision 0

CREV System Isolation Instrumentation B 3.3.7.1 BASES SURVEILLANCE The Surveillances are modified by a Note to indicate that REQUIREMENTS when a channel is placed in an inoperable status solely for (continued) performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to BASES 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , provided the associated Function maintains CREV System isolation capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken.

This Note is based on the reliability analysis (Ref. 4) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the CREV System will isolate when necessary.

SR 3.3.7.1.1 Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or The Frequency may be based something even more serious. A CHANNEL CHECK will detect on factors such as operating gross channel failure; thus, it is key to verifying the experience, equipment reliability, instrumentation continues to operate properly between each or plant risk, and is controlled CHANNEL CALIBRATION.

under the Surveillance Frequency Control Program. Agreement criteria are determined by the plant staff, based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.

The Frequency is based upon operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with channels required by the LCO.

(continued)

Quad Cities 1 and 2 B 3.3.7.1-11 Revision 23

CREV System Isolation Instrumentation B 3.3.7.1 BASES SURVEILLANCE SR 3.3.7.1.2 REQUIREMENTS (continued) A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Frequency of 92 days is based on the reliability analyses of Reference 4.

SR 3.3.7.1.3 The calibration of trip units provides a check of the actual trip setpoints. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint The Frequency may be based methodology. The channel must be declared inoperable if the on factors such as operating trip setting is discovered to be less conservative than the experience, equipment reliability, Allowable Value specified in Table 3.3.7.1-1. If the trip or plant risk, and is controlled setting is discovered to be less conservative than accounted under the Surveillance for in the appropriate setpoint methodology, but is not Frequency Control Program. beyond the Allowable Value, the channel performance is still within the requirements of the plant safety analysis. Under these conditions, the setpoint must be readjusted to be equal to or more conservative than the setting accounted for in the appropriate setpoint methodology.

The Frequency of 92 days is based on the reliability analyses of Reference 4.

(continued)

Quad Cities 1 and 2 B 3.3.7.1-12 Revision 23

CREV System Isolation Instrumentation B 3.3.7.1 BASES SURVEILLANCE SR 3.3.7.1.4 and SR 3.3.7.1.5 REQUIREMENTS (continued) A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

The 92 day Frequency of SR 3.3.7.1.4 and the 24 month Frequency of SR 3.3.7.1.5 are based upon the assumption of a 92 day and 24 month calibration interval, respectively, in the determination of the magnitude of equipment drift in the setpoint analysis.

The Frequency may be based on factors such as operating experience, equipment reliability, SR 3.3.7.1.6 or plant risk, and is controlled under the Surveillance The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the Frequency Control Program. OPERABILITY of the required initiation logic for a specific channel. The system functional testing performed in LCO 3.7.4, "Control Room Emergency Ventilation (CREV)

System," overlaps this Surveillance to provide complete testing of the assumed safety function.

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency.

REFERENCES 1. UFSAR, Section 6.4.

2. UFSAR, Section 15.6.4.

3. UFSAR, Section 15.6.5.

4. GENE-770-06-1-A, "Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications,"

December 1992.

5. UFSAR, Section 9.1.4.3.2.

(continued)

Quad Cities 1 and 2 B 3.3.7.1-13 Revision 29

Mechanical Vacuum Pump Trip Instrumentation B 3.3.7.2 BASES ACTIONS C.1, C.2, C.3, and C.4 (continued)

With any Required Action and associated Completion Time not met, the plant must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (Required Action C.4). Alternately, the mechanical vacuum pump may be removed from service since this performs the intended function of the instrumentation (Required Actions C.1 and C.2). An additional option is provided to isolate the main steam lines (Required Action C.3), which may allow operation to continue. Isolating the main steam lines effectively provides an equivalent level of protection by precluding fission product transport to the condenser.

The allowed Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions, or to remove the mechanical vacuum pump from service, or to isolate the main steam lines, in an orderly manner and without challenging plant systems.

SURVEILLANCE The Surveillances are modified by a Note to indicate that REQUIREMENTS when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into the associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided mechanical vacuum pump trip capability is maintained. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken.

This Note is based on the reliability analysis (Ref. 4) assumption of the average time required to perform channel Surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the mechanical vacuum pump will trip when necessary.

SR 3.3.7.2.1 Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter (continued)

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Mechanical Vacuum Pump Trip Instrumentation B 3.3.7.2 BASES SURVEILLANCE SR 3.3.7.2.1 (continued)

REQUIREMENTS indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.

The Frequency is based upon operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the required channels of this LCO.

SR 3.3.7.2.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a The Frequency may be based channel relay may be performed by the verification of the on factors such as operating change of state of a single contact of the relay. This experience, equipment reliability, clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a or plant risk, and is controlled relay. This is acceptable because all of the other required under the Surveillance contacts of the relay are verified by other Technical Frequency Control Program. Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Frequency of 92 days is based on the reliability analysis of Reference 4.

(continued)

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Mechanical Vacuum Pump Trip Instrumentation B 3.3.7.2 BASES SURVEILLANCE SR 3.3.7.2.3 and SR 3.3.7.2.4 REQUIREMENTS (continued) A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology. A Note to SR 3.3.7.2.3 states that radiation detectors are excluded from CHANNEL CALIBRATION since they are calibrated in accordance with SR 3.3.7.2.4.

The Frequency of SR 3.3.7.2.3 is based upon the assumption of a 92 day calibration interval in the determination of the magnitude of equipment drift associated with the channel, except for the radiation detectors, in the setpoint analysis. The Frequency of SR 3.3.7.2.4 is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift for the radiation detector in the setpoint analysis.

SR 3.3.7.2.5 The Frequency may be based on factors such as operating The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the experience, equipment reliability, OPERABILITY of the required trip logic for a specific or plant risk, and is controlled channel. The system functional test of the mechanical under the Surveillance vacuum pump breaker is included as part of this Surveillance Frequency Control Program. and overlaps the LOGIC SYSTEM FUNCTIONAL TEST to provide complete testing of the assumed safety function. Therefore, if a breaker or the isolation valve is incapable of operating, the associated instrument channel(s) would be inoperable.

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency.

(continued)

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LOP Instrumentation B 3.3.8.1 BASES SURVEILLANCE SR 3.3.8.1.1 and SR 3.3.8.1.3 REQUIREMENTS (continued) A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Frequencies of 18 months and 24 months are based on operating experience with regard to channel OPERABILITY and drift, which demonstrates that failure of more than one channel of a given Function in any 18 month or 24 month interval, as applicable, is a rare event.

The Frequency may be based on factors such as operating SR 3.3.8.1.2 and SR 3.3.8.1.4 experience, equipment reliability, or plant risk, and is controlled A CHANNEL CALIBRATION is a complete check of the instrument under the Surveillance loop and the sensor. This test verifies the channel Frequency Control Program.

responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

The Frequency is based upon the assumption of an 18 month or 24 month calibration interval, as applicable, in the determination of the magnitude of equipment drift in the setpoint analysis.

(continued)

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LOP Instrumentation B 3.3.8.1 BASES SURVEILLANCE SR 3.3.8.1.5 REQUIREMENTS (continued) The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the The Frequency may be based OPERABILITY of the required actuation logic for a specific on factors such as operating channel. The system functional testing performed in experience, equipment reliability, LCO 3.8.1 and LCO 3.8.2 overlaps this Surveillance to or plant risk, and is controlled provide complete testing of the assumed safety functions.

under the Surveillance Frequency Control Program.

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency.

REFERENCES 1. UFSAR, Section 8.3.1.8.

2. UFSAR, Section 5.2.

3. UFSAR, Section 6.3.

4. UFSAR, Chapter 15.

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RPS Electric Power Monitoring B 3.3.8.2 BASES ACTIONS D.1 (continued)

If any Required Action and associated Completion Time of Condition A or B are not met in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, the operator must immediately initiate action to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Required Action D.1 results in the least reactive condition for the reactor core and ensures that the safety function of the RPS (e.g., scram of control rods) is not required.

SURVEILLANCE SR 3.3.8.2.1 REQUIREMENTS A CHANNEL FUNCTIONAL TEST is performed on each overvoltage, undervoltage, and underfrequency channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

As noted in the Surveillance, the CHANNEL FUNCTIONAL TEST is The Frequency may be based only required to be performed while the plant is in a on factors such as operating condition in which the loss of the RPS bus will not experience, equipment reliability, jeopardize steady state power operation (the design of the or plant risk, and is controlled system is such that the power source must be removed from under the Surveillance service to conduct the Surveillance). The 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is Frequency Control Program. intended to indicate an outage of sufficient duration to allow for scheduling and proper performance of the is Surveillance.

The 184 day Frequency and the Note in the Surveillance are based on guidance provided in Generic Letter 91-09 (Ref. 2).

(continued)

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RPS Electric Power Monitoring B 3.3.8.2 BASES SURVEILLANCE SR 3.3.8.2.2 REQUIREMENTS (continued) CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies that the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

The Frequency is based on the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

SR 3.3.8.2.3 Performance of a system functional test demonstrates that, with a required system actuation (simulated or actual) signal, the logic of the system will automatically trip open the associated power monitoring assembly. The system The Frequency may be based functional test shall include actuation of the protective on factors such as operating relays, tripping logic, and output circuit breakers. Only experience, equipment reliability, one signal per power monitoring assembly is required to be or plant risk, and is controlled tested. This Surveillance overlaps with the CHANNEL under the Surveillance CALIBRATION to provide complete testing of the safety Frequency Control Program. function. The system functional test of the Class 1E circuit breakers is included as part of this test to provide complete testing of the safety function. If the breakers are incapable of operating, the associated electric power monitoring assembly would be inoperable.

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency.

REFERENCES 1. UFSAR, Section 7.2.2.

2. NRC Generic Letter 91-09, "Modification of Surveillance Interval for the Electrical Protective Assemblies in Power Supplies for the Reactor Protection System."

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Recirculation Loops Operating B 3.4.1 BASES (continued)

SURVEILLANCE SR 3.4.1.1 REQUIREMENTS This SR ensures the recirculation loops are within the allowable limits for mismatch. At low core flow (i.e.,

< 70% of rated core flow), the APLHGR, LHGR, and MCPR requirements provide larger margins to the fuel cladding integrity Safety Limit such that the potential adverse effect of early boiling transition during a LOCA is reduced.

A larger flow mismatch can therefore be allowed when core flow is < 70% of rated core flow. The jet pump loop flow, as used in this Surveillance, is the summation of the flows The Frequency may be based on factors such as operating from all of the jet pumps associated with a single experience, equipment reliability, recirculation loop.

or plant risk, and is controlled under the Surveillance The mismatch is measured in terms of percent of rated core Frequency Control Program. flow. If the flow mismatch exceeds the specified limits, the loop with the lower flow is considered not in operation.

This SR is not required when both loops are not in operation since the mismatch limits are meaningless during single loop or natural circulation operation. The Surveillance must be performed within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after both loops are in operation.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is consistent with the Surveillance Frequency for jet pump OPERABILITY verification and has been shown by operating experience to be adequate to detect off normal jet pump loop flows in a timely manner.

REFERENCES 1. UFSAR, Section 6.3.3.2.

2. UFSAR, Chapter 15.

3. UFSAR, Section 6.3.3.2.2.4.

4. UFSAR, Section 15.3.6.

Quad Cities 1 and 2 B 3.4.1-6 Revision 19

Jet Pumps B 3.4.2 BASES SURVEILLANCE 3.4.2.1 (continued)

REQUIREMENTS the loop average is repeatable. An appreciable change in this relationship is an indication that increased (or reduced) resistance has occurred in one of the jet pumps.

The deviations from normal are considered indicative of a potential problem in the recirculation drive flow or jet pump system (Ref. 2). Normal flow ranges and established The Frequency may be based jet pump flow patterns are established by plotting on factors such as operating historical data as discussed in Reference 2.

experience, equipment reliability, or plant risk, and is controlled Flow from a jet pump may be used to simulate the flow in the under the Surveillance other jet pump with the same riser. This allowance may be Frequency Control Program. used for two jet pumps, except that the two jet pumps may not be both of the calibrated jet pumps in the same recirculation loop. An analysis has been performed which demonstrated the acceptability of this method (Refs. 4 and 5).

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency has been shown by operating experience to be timely for detecting jet pump degradation and is consistent with the Surveillance Frequency for recirculation loop OPERABILITY verification.

This SR is modified by two Notes. Note 1 allows this Surveillance not to be performed until 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after the associated recirculation loop is in operation, since these checks can only be performed during jet pump operation. The 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is an acceptable time to establish conditions appropriate for data collection and evaluation.

Note 2 allows this SR not to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after THERMAL POWER exceeds 25% RTP. During low flow conditions, jet pump noise approaches the threshold response of the associated flow instrumentation and precludes the collection of repeatable and meaningful data. The 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is an acceptable time to establish conditions appropriate to perform this SR.

REFERENCES 1. UFSAR, Section 6.3.

(continued)

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Safety and Relief Valves B 3.4.3 BASES SURVEILLANCE SR 3.4.3.2 (continued)

REQUIREMENTS For the ERVs, the actuator test is performed with the pilot valve actuator mounted in its normal position. This will allow testing of the manual actuation electrical circuitry, solenoid actuator, pilot operating lever, and pilot plunger.

This test will verify pilot valve movement. However, since this test is performed prior to establishing the reactor pressure needed to overcome main valve closure spring force, the main valve will not stroke during the test.

This SR, together with the valve testing performed as required by the ASME Code for pressure relieving devices (ASME OM Code-1998 through 2000 Addenda), verify the capability of each relief valve to perform its function.

Valve testing will be performed at a steam test facility, where the valve (i.e., main valve and pilot valve) and an actuator representative of the actuator used at the plant will be installed on a steam header in the same orientation as the plant installation. The test conditions in the test facility will be similar to those in the plant installation, including ambient temperature, valve insulation, and steam conditions. The valve will then be leak tested, functionally tested to ensure the valve is capable of opening and closing (including stroke time), and leak tested a final time. Valve seat tightness will be verified by a cold bar test, and if not free of fog, leakage will be measured and verified to be below design limits. In addition, for the safety mode of S/RVs, an as-found setpoint The Frequency may be based verification and as-found leak check are performed, followed on factors such as operating by verification of set pressure, and delay. The valve will experience, equipment reliability, then be shipped to the plant without any disassembly or or plant risk, and is controlled alteration of the main valve or pilot valve components.

under the Surveillance Frequency Control Program.

The combination of the valve testing and the valve actuator testing provide a complete check of the capability of the valves to open and close, such that full functionality is demonstrated through overlapping tests, without cycling the valves.

The 24 month Frequency ensures that each solenoid for each relief valve is tested. The 24 month Frequency was developed based on the relief valve tests required by the ASME Code (Ref. 5). Operating experience has shown that these components usually (continued)

Quad Cities 1 and 2 B 3.4.3-6 Revision 35

Safety and Relief Valves B 3.4.3 BASES SURVEILLANCE SR 3.4.3.2 (continued)

REQUIREMENTS pass the Surveillance when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.4.3.3 The Frequency may be based The relief valves, including the S/RV, are required to on factors such as operating actuate automatically upon receipt of specific initiation experience, equipment reliability, signals. A system functional test is performed to verify or plant risk, and is controlled that the mechanical portions (i.e., solenoids) of the under the Surveillance relief valve operate as designed when initiated either by an Frequency Control Program. actual or simulated automatic initiation signal. The LOGIC SYSTEM FUNCTIONAL TESTs in LCO 3.3.5.1, "Emergency Core Cooling System (ECCS) Instrumentation," and LCO 3.3.6.3, "Relief Valve Instrumentation," overlap this SR to provide complete testing of the safety function.

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the surveillance were performed with the reactor at power.

Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency.

Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

This SR is modified by a Note that excludes valve actuation since the valves are individually tested in accordance with SR 3.4.3.2.

REFERENCES 1. UFSAR, Section 5.2.2.1.

2. UFSAR, Section 15.2.3.1.

3. UFSAR, Section 15.2.2.1.

4. UFSAR, Chapter 15.

5. ASME Code for Operation and Maintenance of Nuclear Power Plants.

Quad Cities 1 and 2 B 3.4.3-7 Revision 35

RCS Operational LEAKAGE B 3.4.4 BASES ACTIONS C.1 and C.2 (continued) based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant safety systems.

SURVEILLANCE SR 3.4.4.1 REQUIREMENTS The Frequency may be based The RCS LEAKAGE is monitored by a variety of instruments on factors such as operating designed to provide alarms when LEAKAGE is indicated and to experience, equipment reliability, quantify the various types of LEAKAGE. Leakage detection or plant risk, and is controlled instrumentation is discussed in more detail in the Bases for under the Surveillance LCO 3.4.5, "RCS Leakage Detection Instrumentation." The Frequency Control Program.

drywell floor drain sump flow integrator is typically monitored to determine actual LEAKAGE rates; however, an alternate method which may be used to quantify LEAKAGE is calculating flow rates using sump pump run times. In conjunction with alarms and other administrative controls, a 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency for this Surveillance is appropriate for identifying LEAKAGE and for tracking required trends (Ref. 4).

REFERENCES 1. UFSAR, Sections 3.1.2.4 and 3.1.3.6.

2. GEAP-5620, "Failure Behavior in ASTM A106B Pipes Containing Axial Through-Wall Flaws," April 1968.

3. NUREG-75/067, "Investigation and Evaluation of Cracking in Austenitic Stainless Steel Piping of Boiling Water Reactor Plants," October 1975.

4. Generic Letter 88-01, Supplement 1, February 1992.

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RCS Leakage Detection Instrumentation B 3.4.5 BASES (continued)

LCO The drywell floor drain sump monitoring system is required to quantify the unidentified LEAKAGE from the RCS. Thus, for the system to be considered OPERABLE, the flow monitoring portion of the system must be OPERABLE. The other monitoring system (particulate) provides early alarms to the operators so closer examination of other detection systems will be made to determine the extent of any corrective action that may be required. With the leakage detection systems inoperable, monitoring for LEAKAGE in the RCPB is degraded.

APPLICABILITY In MODES 1, 2, and 3, leakage detection systems are required to be OPERABLE to support LCO 3.4.4. This Applicability is consistent with that for LCO 3.4.4.

ACTIONS A.1 With the drywell floor drain sump monitoring system inoperable, no other form of sampling can provide the equivalent information to quantify leakage. However, the primary containment atmospheric particulate monitoring system will provide indication of changes in leakage.

With the drywell floor drain sump monitoring system as required by inoperable, but with RCS unidentified and total LEAKAGE being determined every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (SR 3.4.4.1), operation may continue for 30 days. The 30 day Completion Time of Required Action A.1 is acceptable, based on operating experience, considering the multiple forms of leakage detection that are still available.

B.1 and B.2 With the primary containment atmospheric particulate monitoring system inoperable, grab samples of the primary containment atmosphere must be taken and analyzed to provide periodic leakage information. Provided a sample is obtained and analyzed once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , the plant may be operated for up to 30 days to allow restoration of the required monitor.

(continued)

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RCS Leakage Detection Instrumentation B 3.4.5 BASES SURVEILLANCE SR 3.4.5.1 REQUIREMENTS (continued) This SR is for the performance of a CHANNEL CHECK of the primary containment atmospheric particulate monitoring system. The check gives reasonable confidence that the channel is operating properly. The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is based on instrument reliability and is reasonable for detecting off normal conditions.

SR 3.4.5.2 This SR is for the performance of a CHANNEL FUNCTIONAL TEST of the required RCS leakage detection instrumentation. The The Frequency may be based test ensures that the monitors can perform their function in on factors such as operating the desired manner. The test also verifies the relative experience, equipment reliability, accuracy of the instrument string. A successful test of the or plant risk, and is controlled required contact(s) of a channel relay may be performed by under the Surveillance the verification of the change of state of a single contact Frequency Control Program.

of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. The Frequency of 31 days considers instrument reliability, and operating experience has shown it proper for detecting degradation.

SR 3.4.5.3 This SR is for the performance of a CHANNEL CALIBRATION of required leakage detection instrumentation channels. The calibration verifies the accuracy of the instrument string, including the instruments located inside containment. The Frequency of 24 months is a typical refueling cycle and considers channel reliability. Operating experience has proven this Frequency is acceptable.

(continued)

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RCS Specific Activity B 3.4.6 BASES ACTIONS B.1, B.2.1, B.2.2.1, and B.2.2.2 (continued) challenging plant systems. Also, the allowed Completion Times for Required Actions B.2.2.1 and B.2.2.2 for placing the unit in MODES 3 and 4 are reasonable, based on operating experience, to achieve the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.4.6.1 REQUIREMENTS This Surveillance is performed to ensure iodine remains within limit during normal operation. The 7 day Frequency is adequate to trend changes in the iodine activity level.

The Frequency may be based on factors such as operating This SR is modified by a Note that requires this experience, equipment reliability, Surveillance to be performed only in MODE 1 because the or plant risk, and is controlled level of fission products generated in other MODES is much under the Surveillance less.

Frequency Control Program.

REFERENCES 1. 10 CFR 50.67.

2. UFSAR, Section 15.6.4.

Quad Cities 1 and 2 B 3.4.6-4 Revision 31

RHR Shutdown Cooling SystemHot Shutdown B 3.4.7 BASES (continued)

SURVEILLANCE SR 3.4.7.1 REQUIREMENTS Verifying the correct alignment for manual and power operated valves in the two RHR shutdown cooling subsystems' flow paths provides assurance that the proper flow paths will exist for RHR operation. This SR does not apply to The Frequency may be based valves that are locked, sealed, or otherwise secured in on factors such as operating position since these were verified to be in the correct experience, equipment reliability, position prior to locking, sealing, or securing. A valve or plant risk, and is controlled that can be manually (from the control room or locally) under the Surveillance aligned is allowed to be in a non-RHR shutdown cooling Frequency Control Program. position provided the valve can be repositioned. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of potentially being mispositioned are in the correct position.

This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is sufficient in view of other visual and audible indications available to the operator for monitoring the RHR subsystem in the control room.

This Surveillance is modified by a Note allowing sufficient time to align the RHR System for shutdown cooling operation after clearing the pressure interlock that isolates the system, or for placing a recirculation pump in operation.

The Note takes exception to the requirements of the Surveillance being met (i.e., verification that valves are aligned or can be aligned is not required for this initial 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months period), which also allows entry into the Applicability of this Specification in accordance with SR 3.0.4 since the Surveillance will not be "not met" at the time of entry into the Applicability.

REFERENCES None.

Quad Cities 1 and 2 B 3.4.7-5 Revision 22

RHR Shutdown Cooling SystemCold Shutdown B 3.4.8 BASES ACTIONS A.2 and A.3 (continued)

Required Actions A.2 and A.3 are modified by Notes that clarify that these Required Actions are only applicable when both RHR shutdown cooling subsystems are inoperable since Condition A is applicable when one or two RHR shutdown cooling subsystems are inoperable.

SURVEILLANCE SR 3.4.8.1 REQUIREMENTS Verifying the correct alignment for manual and power operated valves in the two RHR shutdown cooling subsystems' flow paths provides assurance that the proper flow paths will exist for RHR operation. This SR does not apply to The Frequency may be based valves that are locked, sealed, or otherwise secured in on factors such as operating position since these were verified to be in the correct experience, equipment reliability, position prior to locking, sealing, or securing. A valve or plant risk, and is controlled that can be manually (remote or local) aligned is allowed to under the Surveillance be in a non-RHR shutdown cooling position provided the valve Frequency Control Program. can be repositioned. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of potentially being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is sufficient in view of other visual and audible indications available to the operator for monitoring the RHR subsystem in the control room.

REFERENCES None.

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RCS P/T Limits B 3.4.9 BASES (continued)

SURVEILLANCE SR 3.4.9.1 REQUIREMENTS Verification that operation is within limits is required every 30 minutes when RCS pressure and temperature conditions are undergoing planned changes. This Frequency is considered reasonable in view of the control room indication available to monitor RCS status. Also, since temperature rate of change limits are specified in hourly increments, 30 minutes permits a reasonable time for assessment and correction of minor deviations.

The Frequency may be based Surveillance for heatup, cooldown, or inservice leak and on factors such as operating hydrostatic testing may be discontinued when the criteria experience, equipment reliability, given in the relevant plant procedure for ending the or plant risk, and is controlled under the Surveillance activity are satisfied.

Frequency Control Program.

This SR has been modified with a Note that requires this Surveillance to be performed only during system heatup and cooldown operations and inservice leak and hydrostatic testing.

SR 3.4.9.2 A separate limit is used when the reactor is approaching criticality. Consequently, the RCS pressure and temperature must be verified within the appropriate limits before withdrawing control rods that will make the reactor critical.

Performing the Surveillance within 15 minutes before control rod withdrawal for the purpose of achieving criticality provides adequate assurance that the limits will not be exceeded between the time of the Surveillance and the time of the control rod withdrawal.

SR 3.4.9.3 and SR 3.4.9.4 Differential temperatures within the applicable limits ensure that thermal stresses resulting from the startup of an idle recirculation pump will not exceed design allowances. In addition, compliance with these limits ensures that the assumptions of the analysis for the startup of an idle recirculation loop (Ref. 8) are satisfied.

(continued)

Quad Cities 1 and 2 B 3.4.9-7 Revision 0

RCS P/T Limits B 3.4.9 BASES SURVEILLANCE SR 3.4.9.3 and SR 3.4.9.4 (continued)

REQUIREMENTS Performing the Surveillance within 15 minutes before starting the idle recirculation pump provides adequate assurance that the limits will not be exceeded between the time of the Surveillance and the time of the idle pump start.

An acceptable means of demonstrating compliance with the temperature differential requirement in SR 3.4.9.3 is to compare the temperatures on the bottom head drain line and the saturation temperature corresponding to reactor steam dome pressure. An acceptable means of demonstrating compliance with the temperature differential requirement in SR 3.4.9.4 is to compare the temperatures of the operating recirculation loop and the idle loop.

SR 3.4.9.3 and SR 3.4.9.4 have been modified by a Note that requires the Surveillance to be performed only in MODES 1, 2, 3, and 4. In MODE 5, the overall stress on limiting components is lower. Therefore, T limits are not required. The Notes also state the SRs are only required to be met during a recirculation pump startup since this is when the stresses occur.

SR 3.4.9.5, SR 3.4.9.6, and SR 3.4.9.7 Limits on the reactor vessel flange and head flange temperatures are generally bounded by the other P/T limits during system heatup and cooldown. However, operations approaching MODE 4 from MODE 5 and in MODE 4 with RCS temperature less than or equal to certain specified values require assurance that these temperatures meet the LCO limits.

periodically The flange temperatures must be verified to be above the limits within 30 minutes before and every 30 minutes thereafter while tensioning the vessel head bolting studs to ensure that once the head is tensioned the limits are satisfied. When in MODE 4 with RCS temperature 93°F, 30 minute checks of the flange temperatures are required (continued)

Quad Cities 1 and 2 B 3.4.9-8 Revision 0

RCS P/T Limits B 3.4.9 BASES SURVEILLANCE SR 3.4.9.5, SR 3.4.9.6, and SR 3.4.9.7 (continued)

REQUIREMENTS The Frequency may be based because of the reduced margin to the limits. When in MODE 4 on factors such as operating with RCS temperature 113°F, monitoring of the flange experience, equipment reliability, temperature is required every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to ensure the or plant risk, and is controlled temperature is within the specified limits.

under the Surveillance Frequency Control Program.

The 30 minute Frequency reflects the urgency of maintaining the temperatures within limits, and also limits the time that the temperature limits could be exceeded. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is reasonable based on the rate of temperature change possible at these temperatures.

SR 3.4.9.5 is modified by a Note that requires the Surveillance to be performed only when tensioning the reactor vessel head bolting studs. SR 3.4.9.6 is modified by a Note that requires the Surveillance to be initiated 30 minutes after RCS temperature 93°F in MODE 4. SR 3.4.9.7 is modified by a Note that requires the Surveillance to be initiated 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after RCS temperature 113°F in MODE 4.

The Notes contained in these SRs are necessary to specify when the reactor vessel flange and head flange temperatures are required to be verified to be within the specified limits.

REFERENCES 1. 10 CFR 50, Appendix G.

2. ASME, Boiler and Pressure Vessel Code,Section III, Appendix G.

3. ASTM E 185-82, July 1982.

4. 10 CFR 50, Appendix H.

5. Regulatory Guide 1.99, Revision 2, May 1988.

6. ASME, Boiler and Pressure Vessel Code,Section XI, Appendix E.

7. Letter from M. Banerjee (NRC) to C. M. Crane (Exelon Generation Company, LLC), "Dresden Nuclear Power Station, Units 2 and 3, and Quad Cities Nuclear Power Station, Units 1 and 2 - Issuance of Amendments Regarding Pressure and Temperature Limits (TAC Nos.

MC5160, MC5161, MC5162, and MC5163)," dated October 17, 2005.

8. UFSAR, Section 15.4.4.3.

Quad Cities 1 and 2 B 3.4.9-9 Revision 27

Reactor Steam Dome Pressure B 3.4.10 BASES (continued)

SURVEILLANCE SR 3.4.10.1 REQUIREMENTS Verification that reactor steam dome pressure is 1005 psig ensures that the initial condition of the vessel overpressure protection analysis is met. Operating experience has shown the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency to be sufficient for identifying trends and verifying operation within safety analyses assumptions.

REFERENCES 1. UFSAR, Section 5.2.2.1.

2. UFSAR, Chapter 15.

The Frequency may be based on factors such as operating experience, equipment reliability, or plant risk, and is controlled under the Surveillance Frequency Control Program.

Quad Cities 1 and 2 B 3.4.10-3 Revision 0

ECCSOperating B 3.5.1 BASES ACTIONS H.1 and H.2 (continued) 150 psig within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

I.1 When multiple ECCS subsystems are inoperable, as stated in Condition I, the plant is in a condition outside of the accident analyses. Therefore, LCO 3.0.3 must be entered immediately.

SURVEILLANCE SR 3.5.1.1 REQUIREMENTS The Frequency may be based The flow path piping has the potential to develop voids and on factors such as operating pockets of entrained air. Maintaining the pump discharge experience, equipment reliability, lines of the HPCI System, CS System, and LPCI subsystems or plant risk, and is controlled under the Surveillance full of water ensures that the ECCS will perform properly, Frequency Control Program. injecting its full capacity into the RCS upon demand. This will also prevent a water hammer following an ECCS initiation signal. One acceptable method of ensuring that the lines are full is to vent at the high points. The 31 day Frequency is based on the gradual nature of void buildup in the ECCS piping, the procedural controls governing system operation, and operating experience.

(continued)

Quad Cities 1 and 2 B 3.5.1-10 Revision 22

ECCSOperating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.2 REQUIREMENTS (continued) Verifying the correct alignment for manual, power operated, and automatic valves in the ECCS flow paths provides assurance that the proper flow paths will exist for ECCS operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these were verified to be in the correct position prior to locking, sealing, or securing. A valve that receives an initiation signal is allowed to be in a nonaccident position provided the valve will automatically reposition in the proper stroke time. This SR does not require any testing or The Frequency may be based valve manipulation; rather, it involves verification that on factors such as operating those valves capable of potentially being mispositioned are experience, equipment reliability, in the correct position. This SR does not apply to valves or plant risk, and is controlled that cannot be inadvertently misaligned, such as check under the Surveillance valves. For the HPCI System, this SR also includes the Frequency Control Program.

steam flow path for the turbine and the flow controller position.

The 31 day Frequency of this SR was derived from the Inservice Testing Program requirements for performing valve testing at least once every 92 days. The Frequency of 31 days is further justified because the valves are operated under procedural control and because improper valve position would only affect a single subsystem. This Frequency has been shown to be acceptable through operating experience.

In MODE 3 with reactor steam dome pressure less than the actual RHR cut-in permissive pressure, the RHR System may be required to operate in the shutdown cooling mode to remove decay heat and sensible heat from the reactor. Therefore, this SR is modified by a Note that allows LPCI subsystems to be considered OPERABLE during alignment and operation for decay heat removal, if capable of being manually realigned (remote or local) to the LPCI mode and not otherwise inoperable. Alignment and operation for decay heat removal includes: a) when the system is being realigned to or from the RHR shutdown cooling mode and; b) when the system is in the RHR shutdown cooling mode, whether or not the RHR pump is operating. At the low pressures and decay heat loads associated with operation in MODE 3 with reactor steam dome pressure less than the RHR cut-in permissive pressure, a reduced complement of low pressure ECCS subsystems should provide the required core cooling, thereby allowing operation of RHR shutdown cooling, when necessary.

(continued)

Quad Cities 1 and 2 B 3.5.1-11 Revision 0

ECCSOperating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.3 REQUIREMENTS (continued) Verification every 31 days of the correct breaker alignment to the LPCI swing bus demonstrates that the AC electrical power is available to ensure proper operation of the associated LPCI injection valves and the recirculation pump discharge valves. The 31 day Frequency has been found acceptable based on engineering judgment and operating experience.

The Frequency may be based SR 3.5.1.4 on factors such as operating experience, equipment reliability, Cycling the recirculation pump discharge valves through one or plant risk, and is controlled complete cycle of full travel demonstrates that the valves under the Surveillance are mechanically OPERABLE and will close when required.

Frequency Control Program. Upon initiation of an automatic LPCI subsystem injection signal, these valves are required to be closed to ensure full LPCI subsystem flow injection in the reactor via the recirculation jet pumps. De-energizing the valve in the closed position will also ensure the proper flow path for the LPCI subsystem. Acceptable methods of de-energizing the valve include de-energizing breaker control power, racking out the breaker or removing the breaker.

The Frequency of this SR is in accordance with the Inservice Testing Program. If any recirculation pump discharge valve is inoperable and in the open position, both LPCI subsystems must be declared inoperable.

SR 3.5.1.5, SR 3.5.1.6, and SR 3.5.1.7 The performance requirements of the low pressure ECCS pumps are determined through application of the 10 CFR 50, Appendix K criteria (Ref. 7). This periodic Surveillance is performed (in accordance with the ASME Code (Ref. 11) requirements for the ECCS pumps) to verify that the ECCS pumps will develop the flow rates required by the respective analyses. The low pressure ECCS pump flow rates ensure that adequate core cooling is provided to satisfy the acceptance criteria of Reference 9. The pump flow rates are verified against a test line pressure or system head equivalent to (continued)

Quad Cities 1 and 2 B 3.5.1-12 Revision 35

ECCSOperating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.5, SR 3.5.1.6, and SR 3.5.1.7 (continued)

REQUIREMENTS The Frequency for SR 3.5.1.5 and SR 3.5.1.6 is in accordance with the Inservice Testing Program requirements. The 24 month Frequency for SR 3.5.1.7 is based on the need to perform the Surveillance under the conditions that apply during a startup from a plant outage. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.5.1.8 The ECCS subsystems are required to actuate automatically to perform their design functions. This Surveillance verifies that, with a required system initiation signal (actual or simulated), the automatic initiation logic of HPCI, CS, and LPCI will cause the systems or subsystems to operate as designed, including actuation of the system throughout its emergency operating sequence, automatic pump startup and actuation of all automatic valves to their required positions. This SR also ensures that the HPCI System will The Frequency may be based automatically restart on an RPV lowlow water level signal on factors such as operating received subsequent to an RPV high water level trip and that experience, equipment reliability, the HPCI suction is automatically transferred from the CCST or plant risk, and is controlled to the suppression pool on high suppression pool water level under the Surveillance or low CCST water level. The LOGIC SYSTEM FUNCTIONAL TEST Frequency Control Program.

performed in LCO 3.3.5.1 overlaps this Surveillance to provide complete testing of the assumed safety function.

While this Surveillance can be performed with the reactor at power, operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle.

Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

This SR is modified by a Note that excludes vessel injection/spray during the Surveillance. Since all active components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the Surveillance.

(continued)

Quad Cities 1 and 2 B 3.5.1-14 Revision 0

ECCSOperating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.9 REQUIREMENTS (continued) The ADS designated valves are required to actuate automatically upon receipt of specific initiation signals.

A system functional test is performed to demonstrate that The Frequency may be based the mechanical portions of the ADS function (i.e.,

on factors such as operating solenoids) operate as designed when initiated either by an experience, equipment reliability, actual or simulated initiation signal, causing proper or plant risk, and is controlled under the Surveillance actuation of all the required components. SR 3.5.1.10 and Frequency Control Program. the LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1 overlap this Surveillance to provide complete testing of the assumed safety function.

The 24 month Frequency is based on the need to perform the Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

This SR is modified by a Note that excludes valve actuation since the valves are individually tested in accordance with SR 3.5.1.10.

SR 3.5.1.10 The actuator of each of the ADS Electromatic valves (ERVs) and the dual function safety/relief valves (S/RVs) is stroked to verify that the pilot valve strokes when manually actuated. For the S/RVs, the actuator test is performed by energizing a solenoid that pneumatically actuates a plunger located within the main valve body. The plunger is connected to the second stage disc. When steam pressure actuates the plunger during plant operation, this allows pressure to be vented from the top of the main valve piston, allowing reactor pressure to lift the main valve piston, which opens the main valve disc. The test will verify movement of the plunger in accordance with vendor recommendations. However, since this test is performed prior to establishing the reactor pressure needed to overcome main valve closure forces, the main valve disc will not stroke during the test.

(continued)

Quad Cities 1 and 2 B 3.5.1-15 Revision 20

ECCSOperating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.10 (continued)

REQUIREMENTS For the ERVs, the actuator test is performed with the pilot valve actuator mounted in its normal position. This will allow testing of the manual actuation electrical circuitry, solenoid actuator, pilot operating lever, and pilot plunger.

This test will verify pilot valve movement. However, since this test is performed prior to establishing the reactor pressure needed to overcome main valve closure spring force, the main valve will not stroke during the test.

This SR, together with the valve testing performed as required by the ASME Code for pressure relieving devices (ASME OM Code-1998 through 2000 Addenda), verify the capability of each relief valve to perform its function.

Valve testing will be performed at a steam test facility, where the valve (i.e., main valve and pilot valve) and an actuator representative of the actuator used at the plant will be installed on a steam header in the same orientation as the plant installation. The test conditions in the test facility will be similar to those in the plant installation, including ambient temperature, valve insulation, and steam conditions. The valve will then be leak tested, functionally tested to ensure the valve is capable of opening and closing (including stroke time), and leak tested a final time. Valve seat tightness will be verified by a cold bar test, and if not free of fog, leakage will be measured and verified to be below design limits. In addition, for the safety mode of S/RVs, an as-found setpoint verification and as-found leak check are performed, followed by verification of set pressure, and delay. The valve will then be shipped to the plant without any disassembly or The Frequency may be based alteration of the main valve or pilot valve components.

on factors such as operating experience, equipment reliability, The combination of the valve testing and the valve actuator or plant risk, and is controlled testing provide a complete check of the capability of the under the Surveillance Frequency Control Program. valves to open and close, such that full functionality is demonstrated through overlapping tests, without cycling the valves.

Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

(continued)

Quad Cities 1 and 2 B 3.5.1-16 Revision 20

ECCSOperating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.11 REQUIREMENTS (continued) The LPCI System injection valves and recirculation pump discharge valves are powered from the LPCI swing bus, which must be energized after a single failure, including loss of power from the normal source to the swing bus. Therefore, the automatic transfer capability from the normal power source to the backup power source must be verified to ensure the automatic capability to detect loss of normal power and initiate an automatic transfer to the swing bus backup power source. Verification of this capability every 24 months ensures that AC electrical power is available for proper operation of the associated LPCI injection valves and recirculation pump valves. The swing bus automatic transfer scheme must be OPERABLE for both LPCI subsystems to be OPERABLE. The Frequency of 24 months is based on the need to perform the Surveillance under the conditions that apply during a startup from a plant outage. Operating experience has shown that the components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.5.1.12 Verification every 31 days that ADS pneumatic supply header pressure is > 80 psig ensures adequate nitrogen pressure for reliable Target Rock ADS valve operation. The accumulator on the Target Rock ADS valve provides pneumatic pressure for valve actuation. The design pneumatic supply pressure The Frequency may be based requirements for the accumulator are such that, following a on factors such as operating failure of the pneumatic supply to the accumulator, at least experience, equipment reliability, two valve actuations can occur with the drywell at 70% of or plant risk, and is controlled design pressure. The ECCS safety analysis assumes only one under the Surveillance Frequency Control Program.

actuation to achieve the depressurization required for operation of the low pressure ECCS. This minimum required pressure of > 80 psig is provided by the ADS pneumatic supply header. The 31 day Frequency takes into consideration administrative controls over operation of the nitrogen system and alarm for low nitrogen pressure.

(continued)

Quad Cities 1 and 2 B 3.5.1-17 Revision 12

ECCSShutdown B 3.5.2 BASES SURVEILLANCE SR 3.5.2.1 (continued)

REQUIREMENTS equivalent to 12 ft in both CCSTs when they are crosstied (normal configuration) and 13.5 ft in one CCST when they are not crosstied, ensures that the required low pressure ECCS injection/spray subsystems can supply at least 140,000 gallons of makeup water to the RPV. However, as The Frequency may be based noted, only one required low pressure ECCS injection/spray on factors such as operating subsystem may take credit for the CCST option during OPDRVs.

experience, equipment reliability, During OPDRVs, the volume in the CCST(s) may not provide or plant risk, and is controlled adequate makeup if the RPV were completely drained.

under the Surveillance Frequency Control Program. Therefore, only one low pressure ECCS injection/spray subsystem is allowed to use the CCST(s). This ensures the other required ECCS subsystem has adequate makeup volume.

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency of these SRs was developed considering operating experience related to suppression pool water level and CCST water level variations and instrument drift during the applicable MODES. Furthermore, the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal suppression pool or CCST water level condition.

SR 3.5.2.2, SR 3.5.2.4, and SR 3.5.2.5 The Bases provided for SR 3.5.1.1, SR 3.5.1.5, and SR 3.5.1.8 are applicable to SR 3.5.2.2, SR 3.5.2.4, and SR 3.5.2.5, respectively.

SR 3.5.2.3 Verifying the correct alignment for manual, power operated, and automatic valves in the ECCS flow paths provides assurance that the proper flow paths will exist for ECCS operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve that receives an initiation signal is allowed to be in a nonaccident position provided the valve will automatically reposition in the proper stroke time. This SR does not require any testing or valve manipulation; rather, it (continued)

Quad Cities 1 and 2 B 3.5.2-5 Revision 0

ECCSShutdown B 3.5.2 BASES SURVEILLANCE SR 3.5.2.3 (continued)

REQUIREMENTS involves verification that those valves capable of potentially being mispositioned are in the correct position.

This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The 31 day Frequency is appropriate because the valves are operated under procedural control and the probability of their being mispositioned during this time period is low.

In MODES 4 and 5, the RHR System may be required to operate The Frequency may be based in the shutdown cooling mode to remove decay heat and on factors such as operating sensible heat from the reactor. Therefore, this SR is experience, equipment reliability, modified by a Note that allows one LPCI subsystem to be or plant risk, and is controlled under the Surveillance considered OPERABLE during alignment and operation for decay Frequency Control Program. heat removal, if capable of being manually realigned (remote or local) to the LPCI mode and not otherwise inoperable.

Alignment and operation for decay heat removal includes: a) when the system is being realigned to or from the RHR shutdown cooling mode and; b) when the system is in the RHR shutdown cooling mode, whether or not the RHR pump is operating. Because of the low pressure and low temperature conditions in MODES 4 and 5, sufficient time will be available to manually align and initiate LPCI subsystem operation to provide core cooling prior to postulated fuel uncovery. This will ensure adequate core cooling if an inadvertent RPV draindown should occur.

REFERENCES 1. UFSAR, Section 6.3.3.1.2.1.

Quad Cities 1 and 2 B 3.5.2-6 Revision 0

RCIC System B 3.5.3 BASES ACTIONS B.1 and B.2 (continued)

If the RCIC System cannot be restored to OPERABLE status within the associated Completion Time, or if the HPCI System is simultaneously inoperable, the plant must be brought to a condition in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and reactor steam dome pressure reduced to 150 psig within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.5.3.1 REQUIREMENTS The Frequency may be based The flow path piping has the potential to develop voids and on factors such as operating pockets of entrained air. Maintaining the pump discharge experience, equipment reliability, line of the RCIC System full of water ensures that the or plant risk, and is controlled system will perform properly, injecting its full capacity under the Surveillance Frequency Control Program. into the Reactor Coolant System upon demand. This will also prevent a water hammer following an initiation signal. One acceptable method of ensuring the line is full is to vent at the high points. The 31 day Frequency is based on the gradual nature of void buildup in the RCIC piping, the procedural controls governing system operation, and operating experience.

SR 3.5.3.2 Verifying the correct alignment for manual, power operated, and automatic valves (including the RCIC pump flow controller) in the RCIC flow path provides assurance that the proper flow path will exist for RCIC operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve that receives an initiation signal is allowed to be in a nonaccident position provided the valve will automatically reposition in the proper stroke time. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of potentially being mispositioned are in the correct position. This SR does not apply to valves that (continued)

Quad Cities 1 and 2 B 3.5.3-4 Revision 22

RCIC System B 3.5.3 BASES SURVEILLANCE SR 3.5.3.2 (continued)

REQUIREMENTS cannot be inadvertently misaligned, such as check valves.

For the RCIC System, this SR also includes the steam flow path for the turbine and the flow controller position.

The 31 day Frequency of this SR was derived from the Inservice Testing Program requirements for performing valve testing at least once every 92 days. The Frequency of 31 days is further justified because the valves are operated under procedural control and because improper valve position would affect only the RCIC System. This Frequency has been The Frequency may be based shown to be acceptable through operating experience.

on factors such as operating experience, equipment reliability, or plant risk, and is controlled under the Surveillance SR 3.5.3.3 and SR 3.5.3.4 Frequency Control Program.

The RCIC pump flow rates ensure that the system can maintain reactor coolant inventory during pressurized conditions with the RPV isolated. The flow tests for the RCIC System are performed at two different pressure ranges such that system capability to provide rated flow against a system head corresponding to reactor pressure is tested both at the higher and lower operating ranges of the system. The required system head should overcome the RPV pressure and associated discharge line losses. Adequate reactor steam pressure must be available to perform these tests.

Additionally, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the RCIC System diverts steam flow. Therefore, sufficient time is allowed after adequate pressure and flow are achieved to perform these SRs.

Reactor steam pressure must be 920 psig to perform SR 3.5.3.3 and 150 psig to perform SR 3.5.3.4. Adequate steam flow is represented by at least 1 turbine bypass valve open. Reactor startup is allowed prior to performing the low pressure Surveillance because the reactor pressure is low and the time allowed to satisfactorily perform the Surveillance is short. The reactor pressure is allowed to be increased to normal operating pressure since it is assumed that the low pressure Surveillance has been satisfactorily completed and there is no indication or reason to believe that RCIC is inoperable. Therefore, these SRs are modified by Notes that state the Surveillances are not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after the (continued)

Quad Cities 1 and 2 B 3.5.3-5 Revision 22

RCIC System B 3.5.3 BASES SURVEILLANCE SR 3.5.3.3 and SR 3.5.3.4 (continued)

REQUIREMENTS reactor steam pressure and flow are adequate to perform the test. The 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowed for the flow tests after the required pressure and flow are reached are sufficient to achieve stable conditions for testing and provides a reasonable time to complete the SRs.

A 92 day Frequency for SR 3.5.3.3 is consistent with the Inservice Testing Program requirements. The 24 month Frequency for SR 3.5.3.4 is based on the need to perform the Surveillance under conditions that apply during a startup from a plant outage. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle.

Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.5.3.5 The RCIC System is required to actuate automatically in order to verify its design function satisfactorily. This Surveillance verifies that, with a required system initiation signal (actual or simulated), the automatic initiation logic of the RCIC System will cause the system to operate as designed, i.e., actuation of the system throughout its emergency operating sequence; which includes, automatic pump startup and actuation of all automatic valves to their required positions. This surveillance also ensures The Frequency may be based the RCIC System will automatically restart on an RPV on factors such as operating low-low water level signal received subsequent to an RPV experience, equipment reliability, high water level trip and that the suction is automatically or plant risk, and is controlled transferred from the CCST to the suppression pool on a CCST under the Surveillance Frequency Control Program.

low water level signal. The LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.2 overlaps this Surveillance to provide complete testing of the assumed design function.

While this Surveillance can be performed with the reactor at power, operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle.

Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

(continued)

Quad Cities 1 and 2 B 3.5.3-6 Revision 22

Primary Containment B 3.6.1.1 BASES (continued)

SURVEILLANCE SR 3.6.1.1.1 REQUIREMENTS Maintaining the primary containment OPERABLE requires compliance with the visual examinations and leakage rate test requirements of the Primary Containment Leakage Rate Testing Program. Failure to meet air lock leakage limit (SR 3.6.1.2.1) or main steam isolation valve leakage limit (SR 3.6.1.3.10) does not necessarily result in a failure of this SR. The impact of the failure to meet these SRs must be evaluated against the Type A, B, and C acceptance criteria of the Primary Containment Leakage Rate Testing Program.

As left leakage prior to the first startup after performing a required Primary Containment Leakage Rate Testing Program leakage test is required to be < 0.6 La for combined Type B and C leakage, and 0.75 La for overall Type A leakage. At all other times between required leakage rate tests, the acceptance criteria is based on an overall Type A leakage limit of 1.0 La. At 1.0 La the offsite dose consequences are bounded by the assumptions of the safety analysis. The Frequency is required by the Primary Containment Leakage Rate Testing Program.

SR 3.6.1.1.2 Maintaining the pressure suppression function of the primary containment requires limiting the leakage from the drywell to the suppression chamber. Thus, if an event were to occur that pressurized the drywell, the steam would be directed through the downcomers into the suppression pool. This SR measures drywell-to-suppression chamber differential pressure during a 15 minute period to ensure that the The Frequency may be based leakage paths that would bypass the suppression pool are on factors such as operating within allowable limits.

experience, equipment reliability, or plant risk, and is controlled Satisfactory performance of this SR can be achieved by under the Surveillance establishing a known differential pressure ( 1.0 psid)

Frequency Control Program. between the drywell and the suppression chamber and verifying that the measured bypass leakage is 2% of the acceptable A / k design value of 0.18 ft2. The leakage test is performed every 24 months. The 24 month Frequency was developed considering it is prudent that this Surveillance be performed during a unit outage and also in view of the (continued)

Quad Cities 1 and 2 B 3.6.1.1-4 Revision 0

Primary Containment B 3.6.1.1 BASES SURVEILLANCE SR 3.6.1.1.2 (continued)

REQUIREMENTS fact that component failures that might have affected this test are identified by other primary containment SRs. Two consecutive test failures, however, would indicate unexpected primary containment degradation, in this event, the Note indicates, increasing the Frequency to once every 12 months is required until the situation is remedied as evidenced by passing two consecutive tests.

REFERENCES 1. UFSAR, Section 6.2.1.

2. UFSAR, Section 15.6.5.

3. 10 CFR 50, Appendix J, Option B.

Quad Cities 1 and 2 B 3.6.1.1-5 Revision 0

Primary Containment Air Lock B 3.6.1.2 BASES (continued)

SURVEILLANCE SR 3.6.1.2.1 REQUIREMENTS Maintaining the primary containment air lock OPERABLE requires compliance with the leakage rate test requirements of the Primary Containment Leakage Rate Testing Program.

This SR reflects the leakage rate testing requirements with respect to air lock leakage (Type B leakage tests). The acceptance criteria were established during initial air lock and primary containment OPERABILITY testing. The periodic testing requirements verify that the air lock leakage does not exceed the allowed fraction of the overall primary containment leakage rate. The Frequency is required by the Primary Containment Leakage Rate Testing Program.

The SR has been modified by two Notes. Note 1 states that an inoperable air lock door does not invalidate the previous successful performance of the overall air lock leakage test.

This is considered reasonable since either air lock door is capable of providing a fission product barrier in the event of a DBA. Note 2 has been added to this SR, requiring the results to be evaluated against the acceptance criteria which are applicable to SR 3.6.1.1.1. This ensures that air lock leakage is properly accounted for in determining the combined Types B and C primary containment leakage rate.

SR 3.6.1.2.2 The air lock interlock mechanism is designed to prevent simultaneous opening of both doors in the air lock. Since both the inner and outer doors of an air lock are designed to withstand the maximum expected post accident primary The Frequency may be based containment pressure, closure of either door will support on factors such as operating primary containment OPERABILITY. Thus, the interlock experience, equipment reliability, feature supports primary containment OPERABILITY while the or plant risk, and is controlled under the Surveillance air lock is being used for personnel transit in and out of Frequency Control Program. the containment. Periodic testing of this interlock demonstrates that the interlock will function as designed and that simultaneous inner and outer door opening will not inadvertently occur. Due to the purely mechanical nature of this interlock, and given that the interlock mechanism is not normally challenged when the primary containment air lock door is used for entry and exit (procedures require strict adherence to single door opening), this test is only required to be performed every 24 months. The 24 month (continued)

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Primary Containment Air Lock B 3.6.1.2 BASES SURVEILLANCE SR 3.6.1.2.2 (continued)

REQUIREMENTS Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage, and the potential for loss of primary containment OPERABILITY if the Surveillance were performed with the reactor at power.

Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency.

The 24 month Frequency is based on engineering judgment and is considered adequate given that the interlock is not challenged during the use of the air lock.

REFERENCES 1. UFSAR, Section 6.2.1.2.1.

2. UFSAR, Section 15.6.5.

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PCIVs B 3.6.1.3 BASES ACTIONS F.1 and F.2 (continued) alternative Required Action is provided to immediately initiate action to restore the valve(s) to OPERABLE status.

This allows RHR shutdown cooling to remain in service while actions are being taken to restore the valve.

SURVEILLANCE SR 3.6.1.3.1 REQUIREMENTS This SR ensures that the 18 inch primary containment vent and purge valves are closed as required or, if open, opened for an allowable reason. If a vent or purge valve is opened in violation of this SR, the valve is considered inoperable.

The torus purge valve, 1601-56, is normally open for pressure control, therefore this valve is excluded from this SR. However, this is acceptable since this valve is designed to automatically close on LOCA conditions. The SR is modified by a Note stating that the SR is not required to be met when the vent or purge valves are open for the stated reasons. The Note states that these valves may be opened The Frequency may be based for inerting, de-inerting, pressure control, ALARA or air on factors such as operating quality considerations for personnel entry, or Surveillances experience, equipment reliability, that require the valves to be open provided the drywell vent or plant risk, and is controlled and purge valves and their associated suppression chamber under the Surveillance Frequency Control Program. vent and purge valves are not open simultaneously. The 18 inch vent and purge valves are capable of closing in the environment following a LOCA. Therefore, these valves are allowed to be open for limited periods of time. The 31 day Frequency is consistent with other PCIV requirements discussed in SR 3.6.1.3.2.

SR 3.6.1.3.2 This SR verifies that each primary containment isolation manual valve and blind flange that is located outside primary containment and not locked, sealed, or otherwise secured and is required to be closed during accident conditions, is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside the primary containment boundary is within design limits.

(continued)

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PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.2 (continued)

REQUIREMENTS This SR does not require any testing or valve manipulation.

Rather, it involves verification that those PCIVs outside primary containment, and capable of being mispositioned, are in the correct position. Since verification of position for PCIVs outside primary containment is relatively easy, the 31 day Frequency was chosen to provide added assurance that the PCIVs are in the correct positions. This SR does not apply to valves that are locked, sealed, or otherwise The Frequency may be based secured in the closed position, since these were verified to on factors such as operating be in the correct position upon locking, sealing, or experience, equipment reliability, securing.

or plant risk, and is controlled under the Surveillance Two Notes have been added to this SR. The first Note allows Frequency Control Program.

valves and blind flanges located in high radiation areas to be verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable since access to these areas is typically restricted for ALARA reasons. Therefore, the probability of misalignment of these PCIVs, once they have been verified to be in the proper position, is low. A second Note has been included to clarify that PCIVs open under administrative controls are not required to meet the SR during the time that the PCIVs are open. These controls consist of stationing a dedicated operator at the controls of the valve, who is in continuous communication with the control room. In this way the penetration can be rapidly isolated when a need for primary containment isolation is indicated.

SR 3.6.1.3.3 This SR verifies that each primary containment manual isolation valve and blind flange located inside primary containment and not locked, sealed, or otherwise secured and is required to be closed during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside the primary containment boundary is within design limits. For PCIVs inside primary containment, the Frequency "prior to entering MODE 2 or 3 from MODE 4 if primary containment was de-inerted while in MODE 4, if not performed within the previous 92 days" is appropriate since these PCIVs are (continued)

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PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.3 (continued)

REQUIREMENTS operated under administrative controls and the probability of their misalignment is low. This SR does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing, or securing.

Two Notes have been added to this SR. The first Note allows valves and blind flanges located in high radiation areas to be verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable since the primary containment is inerted and access to these areas is typically restricted during MODES 1, 2, and 3 for ALARA reasons. Therefore, the probability of misalignment of these PCIVs, once they have been verified to be in their proper position, is low. A second Note has been included to clarify that PCIVs that are open under administrative controls are not required to meet the SR during the time that the PCIVs are open. These controls consist of stationing a dedicated operator at the controls of the valve, who is in continuous communication with the control room. In this way the penetration can be rapidly isolated when a need for primary containment isolation is indicated.

The Frequency may be based SR 3.6.1.3.4 on factors such as operating experience, equipment reliability, The traversing incore probe (TIP) shear isolation valves are or plant risk, and is controlled actuated by explosive charges. Surveillance of explosive under the Surveillance Frequency Control Program.

charge continuity provides assurance that TIP valves will actuate when required. Other administrative controls, such as those that limit the shelf life of the explosive charges, must be followed. The 31 day Frequency is based on operating experience that has demonstrated the reliability of the explosive charge continuity.

(continued)

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PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.5 REQUIREMENTS (continued) Verifying the isolation time of each power operated, automatic PCIV is within limits is required to demonstrate OPERABILITY. MSIVs may be excluded from this SR since MSIV full closure isolation time is demonstrated by SR 3.6.1.3.6.

The isolation time test ensures that each valve will isolate in a time period less than or equal to that assumed in the safety analyses. The Frequency of this SR is in accordance with the requirements of the Inservice Testing Program.

SR 3.6.1.3.6 Verifying that the isolation time of each MSIV is within the specified limits is required to demonstrate OPERABILITY.

The isolation time test ensures that the MSIV will isolate in a time period that does not exceed the times assumed in the DBA and transient analyses. This ensures that the calculated radiological consequences of these events remain within 10 CFR 50.67 limits. The Frequency of this SR is in accordance with the requirements of the Inservice Testing Program.

SR 3.6.1.3.7 The Frequency may be based Automatic PCIVs close on a primary containment isolation on factors such as operating signal to prevent leakage of radioactive material from experience, equipment reliability, primary containment following a DBA. This SR ensures that or plant risk, and is controlled each automatic PCIV will actuate to its isolation position under the Surveillance Frequency Control Program. on a primary containment isolation signal. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.6.1, "Primary Containment Isolation Instrumentation," overlaps this SR to provide complete testing of the safety function. The 24 month Frequency was developed considering it is prudent that this Surveillance be performed only during a unit outage since isolation of penetrations would eliminate cooling water flow and disrupt the normal operation of many critical components. Operating experience has shown that these components usually pass this Surveillance when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

(continued)

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PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.8 REQUIREMENTS (continued) This SR requires a demonstration that a representative sample of reactor instrumentation line excess flow check valves (EFCVs) are OPERABLE by verifying that the valves actuate to the isolation position on an actual or simulated instrument line break condition. This test is performed by blowing down the instrument line during an inservice leak or hydrostatic test and verifying a distinctive "click" when the poppet valve seats or a quick reduction in flow. The representative sample consists of an approximately equal number of EFCVs, such that each EFCV is tested at least once every 10 years (nominal). In addition, the EFCVs in the samples are representative of the various plant configurations, models, sizes, and operating environments.

This ensures that any potentially common problem with a specific type or application of EFCV is detected at the earliest possible time. This SR provides assurance that the instrumentation line EFCVs will perform as designed. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. The nominal 10-year interval is based on performance testing as discussed in NEDO-32977-A (Ref. 7). Furthermore, any EFCV failures will be evaluated to determine if additional testing in that test interval is warranted to ensure overall reliability is maintained. Operating experience has demonstrated that these components are highly reliable and that failures to isolate are very infrequent. Therefore, testing of a representative sample was concluded to be acceptable from a reliability standpoint.

The Frequency may be based SR 3.6.1.3.9 on factors such as operating experience, equipment reliability, The TIP shear isolation valves are actuated by explosive or plant risk, and is controlled under the Surveillance charges. An in place functional test is not possible with Frequency Control Program. this design. The explosive squib is removed and tested to provide assurance that the valves will actuate when required. The replacement charge for the explosive squib shall be from the same manufactured batch as the one fired or from another batch that has been certified by having one of the batch successfully fired. The Frequency of 24 months (continued)

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PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.9 (continued)

REQUIREMENTS on a STAGGERED TEST BASIS is considered adequate given the administrative controls on replacement charges and the frequent checks of circuit continuity (SR 3.6.1.3.4). Other administrative controls, such as those that limit the shelf life and operating life, as applicable, of the explosive charges must be followed.

SR 3.6.1.3.10 The analyses in References 2 and 3 are based on leakage that is less than the specified leakage rate. In accordance with the Primary Containment Leakage Rate Testing Program, the as-left leakage rate of each main steam isolation valve path is assumed to be the maximum pathway leakage (larger leakage of two valves in series), and the as-found leakage rate of each main steam isolation valve path is assumed to be the minimum pathway leakage (smaller of either the inboard or outboard isolation valves individual leakage rates). The combined leakage rate limit through all MSIV leakage paths must be < 86 scfh when tested at > 25 psig for both as-left and as-found leakage rate tests. Additionally, the leakage rate limit through each MSIV leakage path is < 34 scfh when tested at > 25 psig. These values correspond to a combined leakage rate of 150 scfh and an individual MSIV leakage rate of 60 scfh, when tested at 48 psig. This ensures that MSIV leakage is properly accounted for in determining the overall impacts of primary containment leakage. The Frequency is required by the Primary Containment Leakage Rate Testing Program.

MSIV leakage is considered part of La.

REFERENCES 1. Technical Requirements Manual.

2 UFSAR, Section 15.6.5.

3. UFSAR, Section 15.6.4.

4. UFSAR, Chapter 15.

5. UFSAR, Section 5.2.2.2.3.

6. UFSAR, Section 6.2.4.1.

7. NEDO-32977-A, "Excess Flow Check Valve Testing Relaxation," June 2000.

Quad Cities 1 and 2 B 3.6.1.3-15 Revision 31

Drywell Pressure B 3.6.1.4 BASES (continued)

ACTIONS A.1 With drywell pressure not within the limit of the LCO, drywell pressure must be restored within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The Required Action is necessary to return operation to within the bounds of the primary containment analysis. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is consistent with the ACTIONS of LCO 3.6.1.1, "Primary Containment," which requires that primary containment be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

B.1 and B.2 If drywell pressure cannot be restored to within the limit within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.1.4.1 REQUIREMENTS Verifying that drywell pressure is within the limit ensures that unit operation remains within the limit assumed in the primary containment analysis. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency of this SR was developed, based on operating experience related to trending of drywell pressure variations during the applicable MODES. Furthermore, the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal drywell pressure condition.

REFERENCES 1. UFSAR, Section 6.2.1.3.2.

The Frequency may be based on factors such as operating experience, equipment reliability, or plant risk, and is controlled under the Surveillance Frequency Control Program.

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Drywell Air Temperature B 3.6.1.5 BASES SURVEILLANCE SR 3.6.1.5.1 (continued)

REQUIREMENT The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency of the SR was developed based on operating experience related to drywell average air temperature variations and temperature instrument drift during the applicable MODES and the low probability of a DBA The Frequency may be based occurring between surveillances. Furthermore, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months on factors such as operating experience, equipment reliability, Frequency is considered adequate in view of other or plant risk, and is controlled indications available in the control room, including alarms, under the Surveillance to alert the operator to an abnormal drywell air temperature Frequency Control Program. condition.

REFERENCES 1. UFSAR, Section 6.2.1.3.

2. UFSAR, Table 6.2-1.

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Low Set Relief Valves B 3.6.1.6 BASES ACTIONS B.1 and B.2 (continued)

If two low set relief valves are inoperable or if the inoperable low set relief valve cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.1.6.1 REQUIREMENTS The actuator of each of the Electromatic low set relief valves (ERVs) is stroked to verify that the pilot valve strokes when manually actuated. For the ERVs, the actuator test is performed with the pilot valve actuator mounted in its normal position. This will allow testing of the manual actuation electrical circuitry, solenoid actuator, pilot operating lever, and pilot plunger. This test will verify pilot valve movement. However, since this test is performed prior to establishing the reactor pressure needed to overcome main valve closure spring force, the main valve will not stroke during the test.

This SR, together with the valve testing performed as required by the ASME Code for pressure relieving devices (Ref. 2) (ASME OM Code -1998 through 2000 Addenda), verify the capability of each relief valve to perform its function.

Valve testing will be performed at a steam test facility, where the valve (i.e., main valve and pilot valve) and an actuator representative of the actuator used at the plant will be installed on a steam header in the same orientation as the plant installation. The test conditions in the test facility will be similar to those in the plant installation, including ambient temperature, valve insulation, and steam conditions. The valve will then be leak tested, functionally tested to ensure the valve is capable of opening and closing (including stroke time), and leak tested a final time. Valve seat tightness will be verified by a cold bar test, and if not free of fog, leakage will be measured and verified to be below design limits. In addition, for the safety mode of S/RVs, an as-found setpoint (continued)

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Low Set Relief Valves B 3.6.1.6 BASES SURVEILLANCE SR 3.6.1.6.1 (continued)

REQUIREMENTS verification and as-found leak check are performed, followed by verification of set pressure, and delay. The valve will then be shipped to the plant without any disassembly or alteration of the main valve or pilot valve components.

The combination of the valve testing and the valve actuator testing provide a complete check of the capability of the valves to open and close, such that full functionality is demonstrated through overlapping tests, without cycling the valves.

The 24 month Frequency was based on the relief valve tests required by the ASME Code (Ref. 2). The Frequency of 24 months ensures that each solenoid for each low set relief valve is tested. Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.6.1.6.2 The low set relief designated relief valves are required to actuate automatically upon receipt of specific initiation The Frequency may be based signals. A system functional test is performed to verify on factors such as operating that the mechanical portions (i.e., solenoids) of the low experience, equipment reliability, set relief function operate as designed when initiated or plant risk, and is controlled either by an actual or simulated automatic initiation under the Surveillance Frequency Control Program.

signal. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.6.3, "Low Set Relief Valve Instrumentation," overlaps this SR to provide complete testing of the safety function.

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency.

Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

This SR is modified by a Note that excludes valve actuation.

This prevents a reactor pressure vessel pressure blowdown.

(continued)

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Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.7 BASES ACTIONS C.1 (continued) are not OPERABLE. Therefore, the inoperable vacuum breaker must be restored to OPERABLE status within 7 days. This is consistent with the Completion Time for Condition A and the fact that the leak tight primary containment boundary is being maintained.

D.1 With two lines with one or more vacuum breakers inoperable for opening, the primary containment boundary is intact.

However, in the event of a containment depressurization, the function of the vacuum breakers is lost. Therefore, all vacuum breakers in one line must be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . This Completion Time is consistent with the ACTIONS of LCO 3.6.1.1, which requires that primary containment be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

E.1 and E.2 If any Required Action and associated Completion time can not be met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.1.7.1 REQUIREMENTS The Frequency may be based Each vacuum breaker is verified to be closed to ensure that on factors such as operating a potential breach in the primary containment boundary is experience, equipment reliability, not present. This Surveillance is performed by observing or plant risk, and is controlled local or control room indications of vacuum breaker under the Surveillance Frequency Control Program.

position. The 14 day Frequency is based on engineering judgment, is considered adequate in view of other indications of vacuum breaker status available to operations personnel, and has been shown to be acceptable through operating experience.

(continued)

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Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.7 BASES SURVEILLANCE SR 3.6.1.7.1 (continued)

REQUIREMENTS Two Notes are added to this SR. The first Note allows reactor-to-suppression chamber vacuum breakers opened in conjunction with the performance of a Surveillance to not be considered as failing this SR. These periods of opening vacuum breakers are controlled by plant procedures and do not represent inoperable vacuum breakers. The second Note is included to clarify that vacuum breakers open due to an actual differential pressure are not considered as failing this SR.

SR 3.6.1.7.2 Each vacuum breaker must be cycled to ensure that it opens properly to perform its design function and returns to its fully closed position. This ensures that the safety analysis assumptions are valid. The 92 day Frequency of this SR was developed based upon Inservice Testing Program requirements to perform valve testing at least once every 92 days.

The Frequency may be based on factors such as operating experience, equipment reliability, SR 3.6.1.7.3 or plant risk, and is controlled under the Surveillance Frequency Control Program. Demonstration of vacuum breaker opening setpoint is necessary to ensure that the safety analysis assumption regarding vacuum breaker full open differential pressure of 0.5 psid is valid. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. For this plant, the 24 month Frequency has been shown to be acceptable, based on operating experience, and is further justified because of other surveillances performed at shorter Frequencies that convey the proper functioning status of each vacuum breaker.

REFERENCES 1. UFSAR, Sections 6.2.1.3.3 and 6.3.3.2.9.

2. UFSAR, Section 6.2.1.2.4.1.

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Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.8 BASES ACTIONS C.1 and C.2 (continued) within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.1.8.1 REQUIREMENTS Each vacuum breaker is verified closed to ensure that this potential large bypass leakage path is not present. This Surveillance is performed by observing the vacuum breaker position indication or by verifying that a differential pressure of 0.5 psid between the suppression chamber and drywell is maintained for 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The 14 day Frequency is based on engineering judgment, is considered adequate in view of other indications of vacuum breaker status available to operations personnel, and has been shown to be acceptable through operating experience.

Two Notes are added to this SR. The first Note allows suppression chamber-to-drywell vacuum breakers opened in conjunction with the performance of a Surveillance to not be considered as failing this SR. These periods of opening vacuum breakers are controlled by plant procedures and do not represent inoperable vacuum breakers. The second Note is included to clarify that vacuum breakers open due to an actual differential pressure are not considered as failing this SR.

The Frequency may be based on factors such as operating experience, equipment reliability, SR 3.6.1.8.2 or plant risk, and is controlled under the Surveillance Frequency Control Program. Each required vacuum breaker must be cycled to ensure that it opens adequately to perform its design function and returns to the fully closed position. This ensures that the safety analysis assumptions are valid. The 31 day Frequency of this SR was developed, based on Inservice Testing Program requirements to perform valve testing at least once every 92 days. A 31 day Frequency was chosen to provide additional assurance that the vacuum breakers are OPERABLE.

In addition, this functional test is required within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after a discharge of steam to the suppression chamber from the relief valves.

(continued)

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Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.8 BASES SURVEILLANCE SR 3.6.1.8.3 REQUIREMENTS (continued) Verification of the vacuum breaker opening setpoint from the closed position is necessary to ensure that the safety analysis assumption regarding vacuum breaker full open differential pressure of 0.5 psid is valid. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance The Frequency may be based were performed with the reactor at power. The 24 month on factors such as operating Frequency has been shown to be acceptable, based on experience, equipment reliability, operating experience, and is further justified because of or plant risk, and is controlled under the Surveillance other surveillances performed at shorter Frequencies that Frequency Control Program. convey the proper functioning status of each vacuum breaker.

REFERENCES 1. UFSAR, Section 6.2.1.2.4.1.

2. UFSAR, Table 6.2-1.

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Suppression Pool Average Temperature B 3.6.2.1 BASES ACTIONS E.1 and E.2 (continued)

Continued addition of heat to the suppression pool with suppression pool temperature > 120°F could result in exceeding the design basis maximum allowable values for primary containment temperature or pressure. Furthermore, if a blowdown were to occur when the temperature was

> 120°F, the maximum allowable bulk and local temperatures could be exceeded very quickly.

SURVEILLANCE SR 3.6.2.1.1 REQUIREMENTS The suppression pool average temperature is regularly monitored to ensure that the required limits are satisfied.

The average temperature is determined by taking an arithmetic average of OPERABLE suppression pool water temperature channels. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency has been shown, based on operating experience, to be acceptable. When heat is being added to the suppression pool by testing, however, it is necessary to monitor suppression pool temperature more frequently. The 5 minute Frequency during testing is Frequency is The Frequency may be based justified by the rates at which tests will heat up the on factors such as operating suppression pool, has been shown to be acceptable based on experience, equipment reliability, operating experience, and provides assurance that allowable or plant risk, and is controlled pool temperatures are not exceeded. The Frequencies are under the Surveillance Frequency Control Program.

further justified in view of other indications available in the control room, including alarms, to alert the operator to an abnormal suppression pool average temperature condition.

REFERENCES 1. UFSAR, Section 6.2.1.3

2. Dresden and Quad Cities Extended Power Uprate Task T0400, Containment System Response, GE-NE-A22-00103-08-01, Rev. 1, December 2000.

Quad Cities 1 and 2 B 3.6.2.1-5 Revision 9

Suppression Pool Water Level B 3.6.2.2 (continued)

BASES ACTIONS B.1 and B.2 (continued)

If suppression pool water level cannot be restored to within limits within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.2.2.1 REQUIREMENTS Verification of the suppression pool water level is to ensure that the required limits are satisfied. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency has been shown to be acceptable based on operating experience. Furthermore, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal suppression pool water level condition.

REFERENCES 1. UFSAR, Section 6.2.

The Frequency may be based on factors such as operating experience, equipment reliability, or plant risk, and is controlled under the Surveillance Frequency Control Program.

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RHR Suppression Pool Cooling B 3.6.2.3 BASES SURVEILLANCE SR 3.6.2.3.1 (continued)

REQUIREMENTS The Frequency of 31 days is justified because the valves are operated under procedural control, improper valve position would affect only a single subsystem, the probability of an event requiring initiation of the system is low, and the system is a manually initiated system. This Frequency has been shown to be acceptable based on operating experience.

The Frequency may be based on factors such as operating SR 3.6.2.3.2 experience, equipment reliability, or plant risk, and is controlled Verifying that each required RHR pump develops a flow rate under the Surveillance 5000 gpm while operating in the suppression pool cooling Frequency Control Program.

mode with flow through the associated heat exchanger ensures that the primary containment peak pressure and temperature can be maintained below the design limits during a DBA (Ref. 1). The flow is a normal test of centrifugal pump performance required by ASME Code (Ref. 2). This test confirms one point on the pump design curve, and the results are indicative of overall performance. Such inservice tests confirm component OPERABILITY, and detect incipient failures by indicating abnormal performance. The Frequency of this SR is in accordance with the Inservice Testing Program.

REFERENCES 1. UFSAR, Section 6.2.

2. ASME Code for Operation and Maintenance of Nuclear Power Plants.

Quad Cities 1 and 2 B 3.6.2.3-4 Revision 35

RHR Suppression Pool Spray B 3.6.2.4 BASES SURVEILLANCE SR 3.6.2.4.1 (continued)

REQUIREMENTS accident analysis. This is acceptable since the RHR suppression pool spray mode is manually initiated. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.

The Frequency of 31 days is justified because the valves are operated under procedural control, improper valve position would affect only a single subsystem, the probability of an event requiring initiation of the system is low, and the system is a manually initiated system. This Frequency has The Frequency may be based been shown to be acceptable based on operating experience.

on factors such as operating experience, equipment reliability, or plant risk, and is controlled SR 3.6.2.4.2 under the Surveillance Frequency Control Program.

This Surveillance is performed every 10 years to verify that the spray nozzles are not obstructed and that spray flow will be provided when required. The 10 year Frequency is adequate to detect degradation in performance due to the passive nozzle design and has been shown to be acceptable through operating experience.

REFERENCES 1. UFSAR, Section 6.2.2.2.

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Drywell-to-Suppression Chamber Differential Pressure B 3.6.2.5 BASES ACTIONS A.1 (continued) differential pressure to within limit and takes into account the low probability of an event that would create excessive suppression chamber loads occurring during this time period.

B.1 If the differential pressure cannot be restored to within limits within the associated Completion Time, the plant must be placed in a MODE in which the LCO does not apply. This is done by reducing power to 15% RTP within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is reasonable, based on operating experience, to reduce reactor power from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.2.5.1 REQUIREMENTS The drywell-to-suppression chamber differential pressure is regularly monitored to ensure that the required limits are satisfied. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency of this SR was developed based on operating experience relative to differential pressure variations and pressure instrument drift during The Frequency may be based applicable MODES and by assessing the proximity to the on factors such as operating specified LCO differential pressure limit. Furthermore, the experience, equipment reliability, 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is considered adequate in view of other or plant risk, and is controlled indications available in the control room, including alarms, under the Surveillance to alert the operator to an abnormal pressure condition.

Frequency Control Program.

REFERENCES None.

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Primary Containment Oxygen Concentration B 3.6.3.1 BASES ACTIONS A.1 (continued) must be restored to < 4.0 v/o within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is allowed when oxygen concentration is 4.0 v/o because of the availability of other hydrogen and oxygen mitigating systems (e.g., post-accident nitrogen purge) and the low probability and long duration of an event that would generate significant amounts of hydrogen and oxygen occurring during this period.

B.1 If oxygen concentration cannot be restored to within limits within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, power must be reduced to 15% RTP within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is reasonable, based on operating experience, to reduce reactor power from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.3.1.1 REQUIREMENTS The primary containment must be determined to be inerted by verifying that oxygen concentration is < 4.0 v/o. The 7 day Frequency is based on the slow rate at which oxygen concentration can change and on other indications of abnormal conditions (which could lead to more frequent checking by operators in accordance with plant procedures).

Also, this Frequency has been shown to be acceptable through operating experience.

REFERENCES 1. Generic Letter 84-09, May 1984.

2. UFSAR, Section 6.2.5.

The Frequency may be based on factors such as operating experience, equipment reliability, or plant risk, and is controlled under the Surveillance Frequency Control Program.

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Secondary Containment B 3.6.4.1 BASES ACTIONS C.1 and C.2 (continued) assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, in either case, inability to suspend movement of recently irradiated fuel assemblies would not be a sufficient reason to require a reactor shutdown.

SURVEILLANCE SR 3.6.4.1.1 REQUIREMENTS This SR ensures that the secondary containment boundary is sufficiently leak tight to preclude exfiltration under expected wind conditions. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency of this SR was developed based on operating experience related to secondary containment vacuum variations during the applicable MODES and the low probability of a DBA occurring.

The Frequency may be based Furthermore, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is considered adequate in on factors such as operating view of other indications available in the control room, experience, equipment reliability, or plant risk, and is controlled including alarms, to alert the operator to an abnormal under the Surveillance secondary containment vacuum condition.

Frequency Control Program.

SR 3.6.4.1.2 and SR 3.6.4.1.4 Verifying that one secondary containment access door in each access opening is closed and each equipment hatch is closed and sealed ensures that the infiltration of outside air of such a magnitude as to prevent maintaining the desired negative pressure does not occur. Verifying that all such openings are closed provides adequate assurance that exfiltration from the secondary containment will not occur.

In this application, the term "sealed" has no connotation of leak tightness. In addition, for equipment hatches that are floor plugs, the "sealed" requirement is effectively met by gravity. Maintaining secondary containment OPERABILITY requires verifying one door in the access opening is closed.

An access opening contains one inner and one outer door. In some cases a secondary containment barrier contains multiple inner or multiple outer doors. For these cases, the access openings share the inner door or the outer door, i.e., the access openings have a common inner or outer door. The intent is to not breach the secondary containment at any (continued)

Quad Cities 1 and 2 B 3.6.4.1-4 Revision 31

Secondary Containment B 3.6.4.1 BASES SURVEILLANCE SR 3.6.4.1.2 and SR 3.6.4.1.4 (continued)

REQUIREMENTS The Frequency may be based time when secondary containment is required. This is on factors such as operating achieved by maintaining the inner or outer portion of the experience, equipment reliability, barrier closed at all times; i.e., all inner doors closed or or plant risk, and is controlled all outer doors closed. Thus each access opening has one under the Surveillance Frequency Control Program. door closed. However, all secondary containment access doors are normally kept closed, except when the access opening is being used for entry and exit or when maintenance is being performed on an access opening. The 31 day Frequency for SR 3.6.4.1.2 has been shown to be adequate, based on operating experience, and is considered adequate in view of the other indications of door status that are available to the operator. The 24 month Frequency for SR 3.6.4.1.4 is considered adequate in view of the existing administrative controls on equipment hatches.

SR 3.6.4.1.3 The SGT System exhausts the secondary containment atmosphere to the environment through appropriate treatment equipment.

Each SGT subsystem is designed to maintain the secondary containment at 0.25 inches of vacuum water gauge for 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months at a flow rate of 4000 cfm. To ensure that all fission products released to the secondary containment are treated, SR 3.6.4.1.3 verifies that a pressure in the secondary containment that is less than the lowest postulated pressure external to the secondary containment boundary can be maintained. When the SGT System is operating as designed, the maintenance of secondary containment pressure cannot be accomplished if the secondary containment boundary is not intact. SR 3.6.4.1.3 demonstrates that the pressure in the secondary containment can be maintained 0.25 inches of vacuum water gauge for 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months using one SGT subsystem at a flow rate 4000 cfm.

The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months test period allows secondary containment to be in thermal equilibrium at steady state conditions. The primary purpose of the SR is to ensure secondary containment boundary integrity. The secondary purpose of the SR is to ensure that the SGT subsystem being tested functions as designed. There is a separate LCO with Surveillance Requirements that serves the primary purpose of ensuring OPERABILITY of the SGT System. This SR need not be performed with each SGT subsystem. The SGT subsystem used for this Surveillance is staggered to ensure that in (continued)

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Secondary Containment B 3.6.4.1 BASES SURVEILLANCE SR 3.6.4.1.3 (continued)

REQUIREMENTS The Frequency may be based addition to the requirements of LCO 3.6.4.3, either SGT on factors such as operating subsystem will perform this test. The inoperability of the experience, equipment reliability, SGT System does not necessarily constitute a failure of this or plant risk, and is controlled Surveillance relative to secondary containment OPERABILITY.

under the Surveillance Frequency Control Program. Operating experience has shown the secondary containment boundary usually passes the Surveillance when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES 1. UFSAR, Section 15.6.5.

2. UFSAR, Section 9.1.4.3.2.

3. NRC Safety Evaluation Report for the Holtec International HI-STORM 100 Storage System (Docket Number 72-1014, Certificate Number 1014, Amendment 2).

Quad Cities 1 and 2 B 3.6.4.1-6 Revision 31

SCIVs B 3.6.4.2 BASES (continued)

SURVEILLANCE SR 3.6.4.2.1 REQUIREMENTS This SR verifies that each secondary containment manual isolation valve and blind flange that is not locked, sealed, or otherwise secured and is required to be closed during The Frequency may be based accident conditions is closed. The SR helps to ensure that on factors such as operating post accident leakage of radioactive fluids or gases outside experience, equipment reliability, of the secondary containment boundary is within design or plant risk, and is controlled under the Surveillance limits. This SR does not require any testing or valve Frequency Control Program. manipulation. Rather, it involves verification that those SCIVs in secondary containment that are capable of being mispositioned are in the correct position.

Since these SCIVs are readily accessible to personnel during normal operation and verification of their position is relatively easy, the 31 day Frequency was chosen to provide added assurance that the SCIVs are in the correct positions. This SR does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing, or securing.

Two Notes have been added to this SR. The first Note applies to valves and blind flanges located in high radiation areas and allows them to be verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable, since access to these areas is typically restricted during MODES 1, 2, and 3 for ALARA reasons. Therefore, the probability of misalignment of these SCIVs, once they have been verified to be in the proper position, is low.

A second Note has been included to clarify that SCIVs that are open under administrative controls are not required to meet the SR during the time the SCIVs are open. These controls consist of stationing a dedicated operator at the controls of the valve, who is in continuous communication with the control room. In this way, the penetration can be rapidly isolated when a need for secondary containment isolation is indicated.

(continued)

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SCIVs B 3.6.4.2 BASES SURVEILLANCE SR 3.6.4.2.2 REQUIREMENTS (continued) Verifying that the isolation time of each power operated, automatic SCIV is within limits is required to demonstrate OPERABILITY. The isolation time test ensures that the SCIV will isolate in a time period less than or equal to that assumed in the safety analyses. The Frequency of this SR is 92 days.

SR 3.6.4.2.3 Verifying that each automatic SCIV closes on a secondary The Frequency may be based containment isolation signal is required to prevent leakage on factors such as operating of radioactive material from secondary containment following experience, equipment reliability, a DBA or other accidents. This SR ensures that each or plant risk, and is controlled automatic SCIV will actuate to the isolation position on a under the Surveillance secondary containment isolation signal. The LOGIC SYSTEM Frequency Control Program.

FUNCTIONAL TEST in LCO 3.3.6.2, "Secondary Containment Isolation Instrumentation," overlaps this SR to provide complete testing of the safety function. While this Surveillance can be performed with the reactor at power, operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES 1. UFSAR, Section 15.6.5.

2. Technical Requirements Manual.

3. UFSAR, Section 9.1.4.3.2.

4. NRC Safety Evaluation Report for the Holtec International HI-STORM 100 Storage System (Docket Number 72-1014, Certificate Number 1014, Amendment 2).

Quad Cities 1 and 2 B 3.6.4.2-7 Revision 31

SGT System B 3.6.4.3 BASES (continued)

SURVEILLANCE SR 3.6.4.3.1 REQUIREMENTS Operating (from the control room using the manual initiation switch) each SGT subsystem for 10 continuous hours ensures that both subsystems are OPERABLE and that all associated controls are functioning properly. It also ensures that blockage, fan or motor failure, or excessive vibration can be detected for corrective action. Operation with the heaters on (automatic heater cycling to maintain temperature) for 10 continuous hours every 31 days eliminates moisture on the adsorbers and HEPA filters. The 31 day Frequency was developed in consideration of the known reliability of fan motors and controls and the redundancy available in the system.

SR 3.6.4.3.2 This SR verifies that the required SGT filter testing is performed in accordance with the Ventilation Filter Testing Program (VFTP). The SGT System filter tests are in accordance with Regulatory Guide 1.52 (Ref. 5). The VFTP includes testing HEPA filter performance, charcoal adsorber efficiency, minimum system flow rate, and the physical properties of the activated charcoal (general use and following specific operations). Specific test frequencies and additional information are discussed in detail in the VFTP.

SR 3.6.4.3.3 The Frequency may be based This SR verifies that each SGT subsystem starts on receipt on factors such as operating of an actual or simulated initiation signal. While this experience, equipment reliability, Surveillance can be performed with the reactor at power, or plant risk, and is controlled under the Surveillance operating experience has shown that these components usually Frequency Control Program. pass the Surveillance when performed at the 24 month Frequency. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.6.2, "Secondary Containment Isolation Instrumentation," overlaps this SR to provide complete testing of the safety function.

Therefore, the Frequency was found to be acceptable from a reliability standpoint.

(continued)

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RHRSW System B 3.7.1 BASES SURVEILLANCE SR 3.7.1.1 (continued)

REQUIREMENTS considered in the correct position, provided it can be realigned to its accident position. This is acceptable The Frequency may be based because the RHRSW System is a manually initiated system.

on factors such as operating experience, equipment reliability, This SR does not require any testing or valve manipulation; or plant risk, and is controlled rather, it involves verification that those valves capable under the Surveillance of being mispositioned are in the correct position. This SR Frequency Control Program.

does not apply to valves that cannot be inadvertently misaligned, such as check valves.

The 31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions.

REFERENCES 1. UFSAR, Section 9.2.1.

2. UFSAR, Section 9.2.5.

3. UFSAR, Section 6.2.

4. UFSAR, Section 6.2.1.3.3.

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DGCW System B 3.7.2 BASES (continued)

SURVEILLANCE SR 3.7.2.1 REQUIREMENTS Verifying the correct alignment for manual valves in each DGCW subsystem flow path provides assurance that the proper flow paths will exist for DGCW subsystem operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves are verified to be in the correct position prior to locking, sealing, or securing. In addition, the valves associated with the ECCS room emergency coolers are also allowed to be in the nonaccident position provided they can be realigned to the accident position. This is acceptable because the cooling capability of these coolers is not needed immediately after a design basis event.

This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.

The 31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions.

The Frequency may be based SR 3.7.2.2 on factors such as operating experience, equipment reliability, This SR ensures that each DGCW subsystem pump will or plant risk, and is controlled automatically start to provide required cooling to the under the Surveillance associated DG heat exchangers when the DG starts. These Frequency Control Program.

starts may be performed using actual or simulated initiation signals.

Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based at the refueling cycle. Therefore, this Frequency is concluded to be acceptable from a reliability standpoint.

REFERENCES 1. UFSAR, Section 9.5.5.

2. UFSAR, Chapter 6.

3. UFSAR, Chapter 15.

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UHS B 3.7.3 BASES (continued)

SURVEILLANCE SR 3.7.3.1 REQUIREMENTS This SR verifies the water level in the intake bay to be sufficient for the proper operation of the RHRSW and DGCW pumps (net positive suction head and pump vortexing are considered in determining this limit). The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on operating experience related to trending of the parameter variations during the applicable The Frequency may be based MODES.

on factors such as operating experience, equipment reliability, or plant risk, and is controlled under the Surveillance SR 3.7.3.2 Frequency Control Program.

Verification of the UHS temperature ensures that the heat removal capabilities of the RHRSW and DGCW Systems are within the assumptions of the DBA analysis. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on operating experience related to trending of the parameter variations during the applicable MODES.

REFERENCES 1. UFSAR, Section 9.2.1.

2. UFSAR, Section 9.5.5.

3. UFSAR, Section 9.2.5.

4. UFSAR, Section 6.2.

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CREV System B 3.7.4 BASES (continued)

SURVEILLANCE SR 3.7.4.1 REQUIREMENTS This SR verifies that the CREV System in a standby mode starts from the control room and continues to operate. This SR includes initiating flow through the HEPA filters and charcoal adsorbers. Standby systems should be checked periodically to ensure that they start and function properly. As the environmental and normal operating conditions of this system are not severe, testing the system Heater once every month provides an adequate check on this system.

Monthly heater operation for 10 continuous hours, during system operation dries out any moisture that has accumulated in the charcoal as a result of humidity in the ambient air.

Furthermore, the 31 day Frequency is based on the known reliability of the equipment.

SR 3.7.4.2 This SR verifies that the required CREV testing is performed in accordance with Specification 5.5.7, "Ventilation Filter Testing Program (VFTP)." The CREV filter tests are in accordance with Regulatory Guide 1.52 (Ref. 4). The VFTP includes testing HEPA filter performance, charcoal adsorber efficiency, system flow rate, and the physical properties of the activated charcoal (general use and following specific operations). Specific test frequencies and additional information are discussed in detail in the VFTP.

The Frequency may be based on factors such as operating experience, equipment reliability, SR 3.7.4.3 or plant risk, and is controlled under the Surveillance Frequency Control Program. This SR verifies that on an actual or simulated initiation signal, the CREV System isolation dampers close. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.7.1.6 overlaps this SR to provide complete testing of the safety function. Operating experience has shown that these components normally pass the SR when performed at the 24 month Frequency. The Frequency of 24 months is based on industry operating experience and is consistent with the typical refueling cycle. Therefore, the Frequency was found to be acceptable from a reliability standpoint.

(continued)

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Control Room Emergency Ventilation AC System B 3.7.5 BASES ACTIONS C.1 and C.2 (continued)

LCO 3.0.3 is not applicable while in MODE 4 or 5. However, since recently irradiated fuel movement can occur in MODE 1, 2, or 3, the Required Actions of Condition C are modified by a Note indicating that LCO 3.0.3 does not apply. If moving recently irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Entering LCO 3.0.3 while in MODE 1, 2, or 3 would require the unit to be shutdown, but would not require immediate suspension of movement of recently irradiated fuel assemblies. The Note to the ACTIONS, "LCO 3.0.3 is not applicable," ensures that the actions for immediate suspension of recently irradiated fuel assembly movement are not postponed due to entry into LCO 3.0.3.

With the Control Room Emergency Ventilation AC System inoperable during movement of recently irradiated fuel assemblies in the secondary containment or during OPDRVs, action must be taken immediately to suspend activities that present a potential for releasing radioactivity that might require isolation of the control room. This places the unit in a condition that minimizes risk.

If applicable, movement of recently irradiated fuel assemblies in the secondary containment must be suspended immediately. Suspension of this activity shall not preclude completion of movement of a component to a safe position.

Also, if applicable, action must be initiated immediately to suspend OPDRVs to minimize the probability of a vessel draindown and subsequent potential for fission product release. Action must continue until the OPDRVs are suspended.

SURVEILLANCE SR 3.7.5.1 REQUIREMENTS The Frequency may be based This SR verifies that the heat removal capability of the on factors such as operating system is sufficient to remove the control room emergency experience, equipment reliability, zone heat load assumed in the safety analyses. The SR or plant risk, and is controlled consists of a combination of testing and calculation. The under the Surveillance Frequency Control Program. 24 month Frequency is appropriate since significant degradation of the Control Room Emergency Ventilation AC System is not expected over this time period.

(continued)

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Main Condenser Offgas B 3.7.6 BASES (continued)

SURVEILLANCE SR 3.7.6.1 REQUIREMENTS This SR, on a 31 day Frequency, requires an isotopic analysis of a representative offgas sample (taken at the recombiner outlet or the SJAE outlet if the recombiner is bypassed) to ensure that the required limits are satisfied.

The noble gases to be sampled are Xe-133, Xe-135, Xe-138, The Frequency may be based Kr-85M, Kr-87, and Kr-88. If the measured rate of on factors such as operating radioactivity increases significantly as indicated by the experience, equipment reliability, radiation monitors located prior to the offgas holdup line or plant risk, and is controlled (by 50% after correcting for expected increases due to under the Surveillance changes in THERMAL POWER), an isotopic analysis is also Frequency Control Program.

performed within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after the increase is noted, to ensure that the increase is not indicative of a sustained increase in the radioactivity rate. The 31 day Frequency is adequate in view of other instrumentation that continuously monitor the offgas, and is acceptable, based on operating experience.

This SR is modified by a Note indicating that the SR is not required to be performed until 31 days after any main steam line is not isolated and the SJAE is in operation. Only in this condition can radioactive fission gases be in the Main Condenser Offgas System at significant rates.

REFERENCES 1. Letter E-DAS-023-00 from D. A. Studley (Scientech-NUS) to R. Tsai (ComEd), dated January 24, 2000.

2. 10 CFR 50.67.

Quad Cities 1 and 2 B 3.7.6-3 Revision 31

Main Turbine Bypass System B 3.7.7 BASES ACTIONS B.1 (continued)

If the Main Turbine Bypass System cannot be restored to OPERABLE status and the MCPR limits for an inoperable Main Turbine Bypass System are not applied, THERMAL POWER must be reduced to < 25% RTP. As discussed in the Applicability section, operation at < 25% RTP results in sufficient margin to the required limits, and the Main Turbine Bypass System is not required to protect fuel integrity during the turbine generator load rejection, turbine trip, and feedwater controller failure transients. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.7.7.1 REQUIREMENTS Cycling each main turbine bypass valve through one complete cycle of full travel demonstrates that the valves are mechanically OPERABLE and will function when required. The 92 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions. Operating experience has shown that these components usually pass the SR when performed at the 92 day Frequency. Therefore, the Frequency is acceptable from a reliability standpoint.

The Frequency may be based on factors such as operating experience, equipment reliability, SR 3.7.7.2 or plant risk, and is controlled under the Surveillance Frequency Control Program. The Main Turbine Bypass System is required to actuate automatically to perform its design function. This SR demonstrates that, with the required system initiation signals, the valves will actuate to their required position.

The 24 month Frequency is based on the need to perform this Surveillance under conditions that apply during a unit outage and because of the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency, which is based on the refueling cycle.

Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

(continued)

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Main Turbine Bypass System B 3.7.7 BASES SURVEILLANCE SR 3.7.7.3 REQUIREMENTS (continued) This SR ensures that the TURBINE BYPASS SYSTEM RESPONSE TIME, as defined in the transient analysis inputs for the cycle, is in compliance with the assumptions of the appropriate safety analyses. The response time limits are specified in the Technical Requirements Manual (Ref. 5).

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage and because of the potential for an unplanned The Frequency may be based transient if the Surveillance were performed with the on factors such as operating reactor at power. Operating experience has shown that these experience, equipment reliability, components usually pass the SR when performed at the or plant risk, and is controlled 24 month Frequency, which is based on the refueling cycle.

under the Surveillance Therefore, the Frequency was concluded to be acceptable from Frequency Control Program.

a reliability standpoint.

REFERENCES 1. UFSAR, Section 7.7.4.

2. UFSAR, Section 15.2.3.2.

3. UFSAR, Section 15.2.2.2.

4. UFSAR, Section 15.1.2.

5. Technical Requirements Manual.

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Spent Fuel Storage Pool Water Level B 3.7.8 BASES (continued)

LCO The specified water level preserves the assumptions of the fuel handling accident analysis (Ref. 2). As such, it is the minimum required for fuel movement within the spent fuel storage pool.

APPLICABILITY This LCO applies during movement of irradiated fuel assemblies in the spent fuel storage pool or whenever movement of new fuel assemblies occurs in the spent fuel storage pool with irradiated fuel assemblies seated in the spent fuel storage pool, since the potential for a release of fission products exists.

ACTIONS A.1 Required Action A.1 is modified by a Note indicating that LCO 3.0.3 does not apply. If moving fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, inability to suspend movement of fuel assemblies is not a sufficient reason to require a reactor shutdown.

When the initial conditions for an accident cannot be met, action must be taken to preclude the accident from occurring. If the spent fuel storage pool level is less than required, the movement of fuel assemblies in the spent fuel storage pool is suspended immediately. Suspension of this activity shall not preclude completion of movement of a fuel assembly to a safe position. This effectively precludes a spent fuel handling accident from occurring.

SURVEILLANCE SR 3.7.8.1 REQUIREMENTS This SR verifies that sufficient water is available in the event of a fuel handling accident. The water level in the spent fuel storage pool must be checked periodically. The 7 day Frequency is acceptable, based on operating experience, considering that the water volume in the pool is normally stable, and all water level changes are controlled by unit procedures.

The Frequency may be based (continued) on factors such as operating experience, equipment reliability, or plant risk, and is controlled under the Surveillance Frequency Control Program.

Quad Cities 1 and 2 B 3.7.8-2 Revision 29

SSMP System B 3.7.9 BASES ACTIONS B.1 and B.2 (continued)

If the SSMP System cannot be restored to OPERABLE status within the associated Completion Time, the plant must be brought to a condition in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and reactor steam dome pressure reduced to 150 psig within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.7.9.1 REQUIREMENTS Verifying the correct alignment for manual, power operated, and automatic valves in the SSMP System flow path provides assurance that the proper flow path will exist for SSMP System operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to The Frequency may be based locking, sealing, or securing. This SR does not require on factors such as operating any testing or valve manipulation; rather, it involves experience, equipment reliability, verification that those valves capable of potentially being or plant risk, and is controlled mispositioned are in the correct position. This SR does not under the Surveillance Frequency Control Program. apply to valves that cannot be inadvertently misaligned, such as check valves. For the SSMP System, this SR also includes the flow controller position since it controls the pump discharge flow control valve position.

The 31 day Frequency of this SR was derived from the Inservice Testing Program requirements for performing valve testing at least once every 92 days. The Frequency of 31 days is further justified because the valves are operated under procedural control and because improper valve position would affect only the SSMP System. This Frequency has been shown to be acceptable through operating experience.

SR 3.7.9.2 The SSMP System pump flow rate ensures that the system can maintain reactor coolant inventory during pressurized conditions with the RPV isolated. The flow test is performed by utilizing the full flow test line to the CCST.

(continued)

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SSMP System B 3.7.9 BASES SURVEILLANCE SR 3.7.9.2 (continued)

REQUIREMENTS The Frequency may be based The requirements include verifying that the pump discharge on factors such as operating pressure is greater than or equal to a pressure that would experience, equipment reliability, produce the desired injection flow including allowances for or plant risk, and is controlled the flow and elevation head losses of the injection line.

under the Surveillance This provides adequate assurance of SSMP System OPERABILITY Frequency Control Program. based on performance at nominal conditions.

A 92 day Frequency for SR 3.7.9.2 is consistent with the Inservice Testing Program requirements.

REFERENCES 1. 10 CFR 50, Appendix R, Section III.G.

2. UFSAR, Section 5.4.6.5.

3. Letter from J.A. Grobe (NRC) to O.D. Kingsley (ComEd),

"NRC Inspection Report 50-254/98011 (DRS);

50-265/98011 (DRS)," dated July 2, 1998.

Quad Cities 1 and 2 B 3.7.9-4 Revision 0

AC SourcesOperating B 3.8.1 BASES SURVEILLANCE operating voltage is also usually specified as 90% of name REQUIREMENTS plate rating. The specified maximum steady state output (continued) voltage of 4368 V is equal to the maximum operating voltage specified for 4000 V motors. It ensures that for a lightly loaded distribution system, the voltage at the terminals of 4000 V motors is no more than the maximum rated operating voltages. The specified minimum and maximum frequencies of the DG are 58.8 Hz and 61.2 Hz, respectively. These values are equal to +/- 2% of the 60 Hz nominal frequency and are derived from the recommendations found in Regulatory Guide 1.9 (Ref. 10).

The Frequency may be based SR 3.8.1.1 on factors such as operating experience, equipment reliability, This SR ensures proper circuit continuity for the offsite AC or plant risk, and is controlled electrical power supply to the onsite distribution network under the Surveillance Frequency Control Program.

and availability of offsite AC electrical power. The breaker alignment verifies that each breaker is in its correct position to ensure that distribution buses and loads are connected to their preferred power source and that appropriate independence of offsite circuits is maintained.

The 7 day Frequency is adequate since breaker position is not likely to change without the operator being aware of it and because its status is displayed in the control room.

SR 3.8.1.2 and SR 3.8.1.8 These SRs help to ensure the availability of the standby electrical power supply to mitigate DBAs and transients and maintain the unit in a safe shutdown condition.

To minimize the wear on moving parts that do not get lubricated when the engine is not running, these SRs have been modified by a Note (Note 1 for SR 3.8.1.2 and Note 1 for SR 3.8.1.8) to indicate that all DG starts for these Surveillances may be preceded by an engine prelube period and followed by a warmup prior to loading.

For the purposes of this testing, the DGs are started from standby conditions. Standby conditions for a DG mean that the diesel engine coolant and oil are being continuously circulated and temperature is being maintained consistent with manufacturer recommendations.

(continued)

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AC SourcesOperating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.2 and SR 3.8.1.8 (continued)

REQUIREMENTS In order to reduce stress and wear on diesel engines, the manufacturer has recommended a modified start in which the starting speed of DGs is limited, warmup is limited to this lower speed, and the DGs are gradually accelerated to synchronous speed prior to loading. These start procedures are the intent of Note 2 of SR 3.8.1.2.

SR 3.8.1.8 requires that, at a 184 day Frequency, the DG starts from standby conditions and achieves required voltage and frequency within 13 seconds. The 13 second start requirement supports the assumptions in the design basis LOCA analysis of UFSAR, Section 6.3 (Ref. 14). The 13 second start requirement is not applicable to SR 3.8.1.2 (see Note 2 of SR 3.8.1.2), when a modified start procedure as described above is used. If a modified start is not used, the 13 second start requirement of SR 3.8.1.8 applies.

Since SR 3.8.1.8 does require a 13 second start, it is more restrictive than SR 3.8.1.2, and it may be performed in lieu of SR 3.8.1.2.

In addition, the DG is required to maintain proper voltage and frequency limits after steady state is achieved. The voltage and frequency limits are normally achieved within 13 seconds. The time for the DG to reach steady state operation, unless the modified DG start method is employed, is periodically monitored and the trend evaluated to identify degradation of governor and voltage regulator performance.

To minimize testing of the common DG, Note 3 of SR 3.8.1.2 and Note 2 of SR 3.8.1.8 allow a single test of the common The Frequency may be based DG (instead of two tests, one for each unit) to satisfy the on factors such as operating requirements for both units. This is allowed since the main experience, equipment reliability, or plant risk, and is controlled purpose of the Surveillance can be met by performing the under the Surveillance test on either unit. However, to the extent practicable, Frequency Control Program. the tests should be alternated between units. If the DG fails one of these Surveillances, the DG should be considered inoperable on both units, unless the cause of the failure can be directly related to only one unit.

The 31 day Frequency for SR 3.8.1.2 is consistent with Regulatory Guide 1.9 (Ref. 10). The 184 day Frequency for (continued)

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AC SourcesOperating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.2 and SR 3.8.1.8 (continued)

REQUIREMENTS SR 3.8.1.8 is a reduction in cold testing consistent with Generic Letter 84-15 (Ref. 7). These Frequencies provide adequate assurance of DG OPERABILITY, while minimizing degradation resulting from testing.

SR 3.8.1.3 This Surveillance verifies that the DGs are capable of synchronizing and accepting a load approximately equivalent to that corresponding to the continuous rating. A minimum run time of 60 minutes is required to stabilize engine temperatures, while minimizing the time that the DG is connected to the offsite source.

Although no power factor requirements are established by this SR, the DG is normally operated at a power factor between 0.8 lagging and 1.0 when running synchronized with the grid. The 0.8 power factor value is the design rating of the machine at a particular kVA. The 1.0 power factor value is an operational condition where the reactive power component is zero, which minimizes the reactive heating of the generator. Operating the generator at a power factor between 0.8 lagging and 1.0 avoids adverse conditions The Frequency may be based associated with underexciting the generator and more closely on factors such as operating represents the generator operating requirements when experience, equipment reliability, performing its safety function (running isolated on its or plant risk, and is controlled under the Surveillance associated 4160 V ESS bus). The load band is provided to Frequency Control Program. avoid routine overloading of the DG. Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.

The 31 day Frequency for this Surveillance is consistent with Regulatory Guide 1.9 (Ref. 10).

Note 1 modifies this Surveillance to indicate that diesel engine runs for this Surveillance may include gradual loading, as recommended by the manufacturer, so that mechanical stress and wear on the diesel engine are minimized.

(continued)

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AC SourcesOperating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.3 (continued)

REQUIREMENTS Note 2 modifies this Surveillance by stating that momentary transients because of changing bus loads do not invalidate this test. Similarly, momentary power factor transients above the limit do not invalidate the test.

Note 3 indicates that this Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations.

Note 4 stipulates a prerequisite requirement for performance of this SR. A successful DG start must precede this test to credit satisfactory performance.

To minimize testing of the common DG, Note 5 allows a single test of the common DG (instead of two tests, one for each unit) to satisfy the requirements for both units. This is allowed since the main purpose of the Surveillance can be met by performing the test on either unit. However, to the extent practicable, the test should be alternated between units. If the DG fails one of these Surveillances, the DG should be considered inoperable on both units, unless the cause of the failure can be directly related to only one unit.

SR 3.8.1.4 This SR provides verification that the level of fuel oil in the day tank, at which fuel oil is automatically added, is above the Specification requirement. The level is expressed as an equivalent volume in gallons, and is selected to ensure adequate fuel oil for a minimum of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months of DG The Frequency may be based operation at full load plus 10%.

on factors such as operating experience, equipment reliability, This SR also provides verification that there is an adequate or plant risk, and is controlled inventory of fuel oil in the storage tanks to support each under the Surveillance Frequency Control Program. DG's operation for approximately 2 days at full load. The approximate 2 day period is sufficient time to place the unit in a safe shutdown condition and to bring in replenishment fuel from an offsite location.

The 31 day Frequency is adequate to ensure that a sufficient supply of fuel oil is available, since low level alarms are (continued)

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AC SourcesOperating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.4 (continued)

REQUIREMENTS provided and facility operators would be aware of any large uses of fuel oil during this period.

SR 3.8.1.5 and SR 3.8.1.7 Microbiological fouling is a major cause of fuel oil degradation. There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water environment in order to survive. Removal of water from the fuel oil day tank once every 31 days eliminates the necessary environment for bacterial survival. This is accomplished by draining a portion of the contents from the bottom of the day tank to the top of the storage tank.

Checking for and removal of any accumulated water from the bulk storage tank once every 92 days also eliminates the necessary environment for bacterial survival. This is the The Frequency may be based most effective means of controlling microbiological fouling.

on factors such as operating In addition, it eliminates the potential for water experience, equipment reliability, entrainment in the fuel oil during DG operation. Water may or plant risk, and is controlled under the Surveillance come from any of several sources, including condensation, Frequency Control Program. ground water, rain water, contaminated fuel oil, and breakdown of the fuel oil by bacteria. Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequencies are established by Regulatory Guide 1.137 (Ref. 12). This SR is for preventive maintenance. The presence of water does not necessarily represent a failure of this SR provided that accumulated water is removed during performance of this Surveillance.

SR 3.8.1.6 This Surveillance demonstrates that each fuel oil transfer pump operates and automatically transfers fuel oil from its associated storage tank to its associated day tank. It is required to support continuous operation of standby power sources. This Surveillance provides assurance that each (continued)

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AC SourcesOperating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.6 (continued)

REQUIREMENTS fuel oil transfer pump is OPERABLE, the fuel oil piping system is intact, the fuel delivery piping is not obstructed, and the controls and control systems for automatic fuel transfer systems are OPERABLE.

The Frequency for this SR is consistent with the Frequency for testing the DGs in SR 3.8.1.3. DG operation for SR 3.8.1.3 is normally long enough that fuel oil level in the day tank will be reduced to the point where the fuel oil transfer pump automatically starts to restore fuel oil level The Frequency may be based by transferring oil from the storage tank.

on factors such as operating experience, equipment reliability, or plant risk, and is controlled SR 3.8.1.9 under the Surveillance Frequency Control Program.

Transfer of each 4160 V ESS bus power supply from the normal offsite circuit to the alternate offsite circuit demonstrates the OPERABILITY of the alternate circuit distribution network to power the shutdown loads. The 24 month Frequency of the Surveillance is based on engineering judgment taking into consideration the plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

Operating experience has shown that these components usually pass the SR when performed on the 24 month Frequency.

Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.8.1.10 Each DG is provided with an engine overspeed trip to prevent damage to the engine. Recovery from the transient caused by the loss of a large load could cause diesel engine overspeed, which, if excessive, might result in a trip of the engine. This Surveillance demonstrates the DG load response characteristics and capability to reject the largest single load without exceeding predetermined voltage and frequency and while maintaining a specified margin to the overspeed trip. The largest single load for each DG is (continued)

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AC SourcesOperating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.10 (continued)

REQUIREMENTS a residual heat removal service water pump (722 kW). The specified load value conservatively bounds the expected kW rating of the single largest loads under accident conditions. This Surveillance may be accomplished by:

a. Tripping the DG output breaker with the DG carrying greater than or equal to its associated single largest post-accident load while paralleled to offsite power, or while solely supplying the bus; or

b. Tripping its associated single largest post-accident load with the DG solely supplying the bus.

Consistent with Regulatory Guide 1.9 (Ref. 10), the load rejection test is acceptable if the diesel speed does not exceed the nominal (synchronous) speed plus 75% of the difference between nominal speed and the overspeed trip setpoint, or 115% of nominal speed, whichever is lower.

This corresponds to 66.73 Hz, which is the nominal speed plus 75% of the difference between nominal speed and the overspeed trip setpoint.

The time, voltage, and frequency tolerances specified in this SR are derived from Regulatory Guide 1.9 (Ref. 10) recommendations for response during load sequence intervals.

The 3 seconds specified in SR 3.8.1.10.b is equal to 60% of the 5 second load sequence interval associated with sequencing the ECCS low pressure pumps during an undervoltage on the bus concurrent with a LOCA. The The Frequency may be based 4 seconds specified in SR 3.8.1.10.c is equal to 80% of the on factors such as operating 5 second load sequence interval associated with sequencing experience, equipment reliability, the ECCS low pressure pumps during an undervoltage on the or plant risk, and is controlled bus concurrent with a LOCA. The voltage and frequency under the Surveillance Frequency Control Program. specified are consistent with the design range of the equipment powered by the DG. SR 3.8.1.10.a corresponds to the maximum frequency excursion, while SR 3.8.1.10.b and SR 3.8.1.10.c are steady state voltage and frequency values to which the system must recover following load rejection.

The 24 month Frequency takes into consideration the plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

(continued)

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AC SourcesOperating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.10 (continued)

REQUIREMENTS This SR is modified by a Note. The reason for the Note is to minimize testing of the common DG and allow a single test of the common DG (instead of two tests, one for each unit) to satisfy the requirements for both units. This is allowed since the main purpose of the Surveillance can be met by performing the test on either unit. If the DG fails one of these Surveillances, the DG should be considered inoperable on both units, unless the cause of the failure can be directly related to only one unit.

SR 3.8.1.11 Consistent with Regulatory Guide 1.9 (Ref. 10), paragraph C.2.2.8, this Surveillance demonstrates the DG capability to reject a full load without overspeed tripping or exceeding the predetermined voltage limits. The DG full load rejection may occur because of a system fault or inadvertent breaker tripping. This Surveillance ensures proper engine generator load response under the simulated test conditions.

This test simulates the loss of the total connected load that the DG experiences following a full load rejection and verifies that the DG does not trip upon loss of the load.

These acceptance criteria provide DG damage protection.

While the DG is not expected to experience this transient during an event, and continues to be available, this The Frequency may be based response ensures that the DG is not degraded for future on factors such as operating application, including reconnection to the bus if the trip experience, equipment reliability, initiator can be corrected or isolated.

or plant risk, and is controlled under the Surveillance Frequency Control Program. In order to ensure that the DG is tested under load conditions that are as close to design basis conditions as possible, a load band (90% to 100%) has been specified based on Regulatory Guide 1.9 (Ref. 10).

The 24 month Frequency takes into consideration the plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

(continued)

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AC SourcesOperating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.12 (continued)

REQUIREMENTS associated breaker during this test may damage the component or system. In lieu of actual demonstration of the connection and loading of these loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

The Frequency of 24 months takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

This SR is modified by a Note. The reason for the Note is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs shall be started from standby conditions, that is, with the engine coolant and oil being continuously circulated and temperature maintained consistent with manufacturer recommendations.

SR 3.8.1.13 Consistent with Regulatory Guide 1.9 (Ref. 10), paragraph C.2.2.5, this Surveillance demonstrates that the DG automatically starts and achieves the required voltage and frequency within the specified time (13 seconds) from the The Frequency may be based design basis actuation signal (LOCA signal). In addition, on factors such as operating the DG is required to maintain proper voltage and frequency experience, equipment reliability, limits after steady state is achieved. The time for the DG or plant risk, and is controlled to reach the steady state voltage and frequency limits is under the Surveillance Frequency Control Program. periodically monitored and the trend evaluated to identify degradation of governor and voltage regulator performance.

The DG is required to operate for 5 minutes. The 5 minute period provides sufficient time to demonstrate stability.

The Frequency of 24 months takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with the expected fuel cycle lengths.

(continued)

Quad Cities 1 and 2 B 3.8.1-27 Revision 10

AC SourcesOperating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.13 (continued)

REQUIREMENTS This SR is modified by a Note. The reason for the Note is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil being continuously circulated and temperature maintained consistent with manufacturer recommendations.

SR 3.8.1.14 Consistent with Regulatory Guide 1.9 (Ref. 10) paragraph C.2.2.12, this Surveillance demonstrates that DG non-critical protective functions (e.g., high jacket water temperature) are bypassed on an ECCS initiation test signal and critical protective functions (engine overspeed and The Frequency may be based generator differential current) trip the DG to avert on factors such as operating substantial damage to the DG unit. The non-critical trips experience, equipment reliability, are bypassed during DBAs and provide an alarm on an abnormal or plant risk, and is controlled under the Surveillance engine condition. This alarm provides the operator with Frequency Control Program. sufficient time to react appropriately. The DG availability to mitigate the DBA is more critical than protecting the engine against minor problems that are not immediately detrimental to emergency operation of the DG.

The 24 month Frequency is based on engineering judgment, takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

SR 3.8.1.15 Regulatory Guide 1.9 (Ref. 10), paragraph C.2.2.9, requires demonstration that the DGs can start and run continuously at full load capability for an interval of not less than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , 22 hours2.546296e-4 days 0.00611 hours 3.637566e-5 weeks 8.371e-6 months of which is at a load equivalent to 90%

to 100% of the continuous rating of the DG and 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months of which is at a load equivalent to 105% to 110% of the continuous rating of the DG. The DG starts for this Surveillance can be performed either from standby or hot conditions. The provisions for prelube and warmup, discussed in SR 3.8.1.2, and for gradual loading, discussed in SR 3.8.1.3, are applicable to this SR.

(continued)

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AC SourcesOperating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.15 (continued)

REQUIREMENTS The Frequency may be based In order to ensure that the DG is tested under load on factors such as operating conditions that are as close to design conditions as experience, equipment reliability, possible, testing must be performed at a power factor as or plant risk, and is controlled close to the accident load power factor as practicable.

under the Surveillance Frequency Control Program. When synchronized with offsite power, the power factor limit is 0.89. This power factor is chosen to bound the actual worst case inductive loading that the DG could experience under design basis accident conditions.

The 24 month Frequency takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

This Surveillance has been modified by three Notes. Note 1 states that momentary transients due to changing bus loads do not invalidate this test. The load band is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY. Similarly, momentary power factor transients above the limit do not invalidate the test. Note 2 is provided in recognition that under certain conditions, it is necessary to allow the Surveillance to be conducted at a power factor other than the specified limit. During the Surveillance, the DG is normally operated paralleled to the grid, which is not the configuration when the DG is performing its safety function following a loss of offsite power (with or without a LOCA). Given the parallel configuration to the grid during the Surveillance, the grid voltage may be such that the DG field excitation level needed to obtain the specified power factor could result in a transient voltage within the DG windings higher than the recommended values if the DG output breaker were to trip during the Surveillance. Therefore, the power factor shall be maintained as close as practicable to the specified limit while still ensuring that if the DG output breaker were to trip during the Surveillance that the maximum DG winding voltage would not be exceeded. To minimize testing of the common DG, Note 3 allows a single test of the common DG (instead of two tests, one for each unit) to satisfy the requirements for both units. This is allowed since the main (continued)

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AC SourcesOperating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.15 (continued)

REQUIREMENTS purpose of the Surveillance can be met by performing the test on either unit. If the DG fails one of these Surveillances, the DG should be considered inoperable on both units, unless the cause of the failure can be directly related to only one unit.

SR 3.8.1.16 This Surveillance demonstrates that the diesel engine can restart from a hot condition, such as subsequent to shutdown from normal Surveillances, and achieve the required voltage and frequency within 13 seconds. The 13 second time is The Frequency may be based derived from the requirements of the accident analysis for on factors such as operating responding to a design basis large break LOCA (Ref. 14). In experience, equipment reliability, or plant risk, and is controlled addition, the DG is required to maintain proper voltage and under the Surveillance frequency limits after steady state is achieved. The time Frequency Control Program. for the DG to reach the steady state voltage and frequency limits is periodically monitored and the trend evaluated to identify degradation of governor and voltage regulator performance.

The 24 month Frequency takes into consideration the plant conditions required to perform the Surveillance, and is intended to be consistent with the expected fuel cycle lengths.

This SR is modified by three Notes. Note 1 ensures that the test is performed with the diesel sufficiently hot. The requirement that the diesel has operated for at least 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months at approximately full load conditions prior to performance of this Surveillance is based on manufacturer recommendations for achieving hot conditions. Momentary transients due to changing bus loads do not invalidate this test. Note 2 allows all DG starts to be preceded by an engine prelube period to minimize wear and tear on the diesel during testing. To minimize testing of the common DG, Note 3 allows a single test of the common DG (instead of two tests, one for each unit) to satisfy the requirements for both units. This is allowed since the main purpose of (continued)

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AC SourcesOperating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.16 (continued)

REQUIREMENTS the Surveillance can be met by performing the test on either unit. If the DG fails one of these Surveillances, the DG should be considered inoperable on both units, unless the cause of the failure can be directly related to only one unit.

SR 3.8.1.17 Consistent with Regulatory Guide 1.9 (Ref. 10),

paragraph C.2.2.11, this Surveillance ensures that the manual synchronization and load transfer from the DG to the The Frequency may be based offsite source can be made and that the DG can be returned on factors such as operating to ready-to-load status when offsite power is restored. It experience, equipment reliability, also ensures that the auto-start logic is reset to allow the or plant risk, and is controlled under the Surveillance DG to reload if a subsequent loss of offsite power occurs.

Frequency Control Program. The DG is considered to be in ready-to-load status when the DG is at rated speed and voltage, the output breaker is open and can receive an auto-close signal on bus undervoltage, and the individual load timers are reset.

The Frequency of 24 months takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

SR 3.8.1.18 Under accident conditions with loss of offsite power loads are sequentially connected to the bus by the automatic load sequence time delay relays. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading of the DGs due to high motor starting currents. The -10% load sequence time interval limit ensures that a sufficient time interval exists for the DG to restore frequency and voltage prior to applying the next load. There is no upper limit for the load sequence time interval since, for a single load interval (i.e., the time between two load blocks), the capability of the DG to restore frequency and voltage prior to applying the second load is not negatively affected by a longer than designed load interval, and if there are additional load blocks (i.e., the design includes multiple load intervals), then (continued)

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AC SourcesOperating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.18 (continued)

REQUIREMENTS the lower limit requirements (-10%) will ensure that sufficient time exists for the DG to restore frequency and voltage prior to applying the remaining load blocks (i.e.,

all load intervals must be 90% of the design interval).

Reference 14 provides a summary of the automatic loading of ESS buses.

The Frequency of 24 months takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

SR 3.8.1.19 In the event of a DBA coincident with a loss of offsite power, the DGs are required to supply the necessary power to ESF systems so that the fuel, RCS, and containment design limits are not exceeded.

This Surveillance demonstrates DG operation, as discussed in The Frequency may be based the Bases for SR 3.8.1.12, during a loss of offsite power on factors such as operating actuation test signal in conjunction with an ECCS initiation experience, equipment reliability, signal. In lieu of actual demonstration of connection and or plant risk, and is controlled under the Surveillance loading of loads, testing that adequately shows the Frequency Control Program. capability of the DG system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

The Frequency of 24 months takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

This SR is modified by a Note. The reason for the Note is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil being continuously circulated and temperature maintained consistent with manufacturer recommendations.

(continued)

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AC SourcesOperating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.20 REQUIREMENTS (continued) This Surveillance demonstrates that the DG starting independence has not been compromised. Also, this Surveillance demonstrates that each engine can achieve proper frequency and voltage within the specified time when the DGs are started simultaneously.

The 10 year Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 10).

This SR is modified by a Note. The reason for the Note is to minimize wear on the DG during testing. For the purpose The Frequency may be based of this testing, the DGs must be started from standby on factors such as operating conditions, that is, with the engine coolant and oil experience, equipment reliability, continuously circulated and temperature maintained or plant risk, and is controlled consistent with manufacturer recommendations.

under the Surveillance Frequency Control Program.

SR 3.8.1.21 With the exception of this Surveillance, all other Surveillances of this Specification (SR 3.8.1.1 through SR 3.8.1.20) are applied only to the given unit AC sources.

This Surveillance is provided to direct that appropriate Surveillances for the required opposite unit AC sources are governed by the applicable opposite unit Technical Specifications. Performance of the applicable opposite unit Surveillances will satisfy the opposite unit requirements, as well as satisfying the given unit Surveillance Requirement. Exceptions are noted to the opposite unit SRs of LCO 3.8.1. SR 3.8.1.9 and SR 3.8.1.20 are excepted since only one opposite unit offsite circuit and DG is required by the given unit's Specification. SR 3.8.1.13, SR 3.8.1.18, and SR 3.8.1.19 are excepted since these SRs test the opposite unit's ECCS initiation signal, which is not needed for the AC electrical power sources to be OPERABLE on the given unit.

The Frequency required by the applicable opposite unit SR also governs performance of that SR for the given unit.

(continued)

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Diesel Fuel Oil and Starting Air B 3.8.3 BASES LCO The starting air system is required to have a minimum (continued) capacity for three successive DG starts without recharging the air start receivers.

APPLICABILITY The AC sources (LCO 3.8.1 and LCO 3.8.2) are required to ensure the availability of the required power to shut down the reactor and maintain it in a safe shutdown condition after an AOO or a postulated DBA. Because stored diesel fuel oil and starting air subsystems support LCO 3.8.1 and LCO 3.8.2, stored diesel fuel oil and starting air are required to be within limits when the associated DG is required to be OPERABLE.

ACTIONS The ACTIONS Table is modified by a Note indicating that separate Condition entry is allowed for each DG. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable DG subsystem. Complying with the Required Actions for one inoperable DG subsystem may allow for continued operation, and subsequent inoperable DG subsystem(s) are governed by separate Condition entry and application of associated Required Actions.

A.1 This Condition is entered as a result of a failure to meet the acceptance criterion for particulates. Normally, trending of particulate levels allows sufficient time to correct high particulate levels prior to reaching the limit of acceptability. Poor sample procedures, contaminated sampling equipment, and errors in laboratory analysis can produce failures that do not follow a trend. Since the presence of particulates does not mean failure of the fuel oil to burn properly in the diesel engine, since particulate concentration is unlikely to change significantly between Surveillance Frequency intervals, and since proper engine performance has been recently demonstrated (within 31 days),

it is prudent to allow a brief period prior to declaring the associated DG inoperable. The 7 day Completion Time allows for further evaluation, resampling, and re-analysis of the DG fuel oil.

(continued)

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Diesel Fuel Oil and Starting Air B 3.8.3 BASES SURVEILLANCE SR 3.8.3.2 (continued)

REQUIREMENTS The Frequency may be based minimum of three engine starts without recharging. The on factors such as operating pressure specified in this SR is intended to support the experience, equipment reliability, lowest value at which the three starts can be accomplished.

or plant risk, and is controlled under the Surveillance Frequency Control Program. The 31 day Frequency takes into account the capacity, capability, redundancy, and diversity of the AC sources and other indications available in the control room, including alarms, to alert the operator to below normal air start pressure.

REFERENCES 1. Regulatory Guide 1.137, Rev. 1, October 1979.

2. ANSI N195, 1976.

3. UFSAR, Chapter 6.

4. UFSAR, Chapter 15.

5. ASTM Standards: D4057-95; D1298-99; D445-97; D93-99c; D4176-93; D2709-96e; D975-98b; D1552-95; D2622-98; D4294-98; D5453-06; and D5452-98.

Quad Cities 1 and 2 B 3.8.3-6 Revision 37

DC SourcesOperating B 3.8.4 BASES ACTIONS F.1 and F.2 (continued)

If the DC electrical power subsystem cannot be restored to OPERABLE status within the required Completion Time, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. The Completion Time to bring the unit to MODE 4 is consistent with the time required in Regulatory Guide 1.93 (Ref. 6).

SURVEILLANCE SR 3.8.4.1 REQUIREMENTS Verifying battery terminal voltage while on float charge for The Frequency may be based the batteries helps to ensure the effectiveness of the on factors such as operating charging system and the ability of the batteries to perform experience, equipment reliability, their intended function. Float charge is the condition in or plant risk, and is controlled under the Surveillance which the charger is supplying the continuous charge Frequency Control Program. required to overcome the internal losses of a battery and maintain the battery in a fully charged state. The voltage requirements are based on the nominal design voltage of the battery and are consistent with the initial voltages assumed in the battery sizing calculations. The 7 day Frequency is conservative when compared with manufacturers recommendations and IEEE-450 (Ref. 7).

SR 3.8.4.2 Visual inspection to detect corrosion of the battery cells and connections, or measurement of the resistance of each intercell and terminal connection, provides an indication of physical damage or abnormal deterioration that could potentially degrade battery performance.

The connection resistance limits established for this SR are within the values established by industry practice. The connection resistance limits of this SR are related to the resistance of individual bolted connections and do not include the resistance of conductive components (e.g.,

cables or conductors located between cells, racks, or tiers).

(continued)

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DC SourcesOperating B 3.8.4 BASES SURVEILLANCE SR 3.8.4.2 (continued)

REQUIREMENTS The Frequency for these inspections, which can detect conditions that can cause power losses due to resistance heating, is 92 days. This Frequency is considered acceptable based on operating experience related to detecting corrosion trends.

SR 3.8.4.3 The Frequency may be based Visual inspection of the battery cells, cell plates, and on factors such as operating battery racks provides an indication of physical damage or experience, equipment reliability, or plant risk, and is controlled abnormal deterioration that could potentially degrade under the Surveillance battery performance. The presence of physical damage or Frequency Control Program. deterioration does not necessarily represent a failure of this SR, provided an evaluation determines that the physical damage or deterioration does not affect the OPERABILITY of the battery (its ability to perform its design function).

The 24 month Frequency for the Surveillance is based on engineering judgement. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.8.4.4 and SR 3.8.4.5 Visual inspection and resistance measurements of intercell and terminal connections provides an indication of physical damage or abnormal deterioration that could indicate degraded battery condition. The anti-corrosion material is used to help ensure good electrical connections and to reduce terminal deterioration. The visual inspection for corrosion is not intended to require removal of and inspection under each terminal connection.

The removal of visible corrosion is a preventive maintenance SR. The presence of visible corrosion does not necessarily represent a failure of this SR, provided visible corrosion is removed during performance of this Surveillance.

(continued)

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DC SourcesOperating B 3.8.4 BASES SURVEILLANCE SR 3.8.4.4 and SR 3.8.4.5 (continued)

REQUIREMENTS The connection resistance limits established for this SR are within the values established by industry practice. The connection resistance limits of this SR are related to the resistance of individual bolted connections and do not include the resistance of conductive components (e.g.,

cables or conductors located between cells, racks, or tiers).

The 24 month Frequency for the Surveillance is based on engineering judgement. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.8.4.6 Battery charger capability requirements are based on the design capacity of the chargers (Ref. 1). According to The Frequency may be based Regulatory Guide 1.32 (Ref. 8), the battery charger supply on factors such as operating experience, equipment reliability, is required to be based on the largest combined demands of or plant risk, and is controlled the various steady state loads and the charging capacity to under the Surveillance restore the battery from the design minimum charge state to Frequency Control Program. the fully charged state, irrespective of the status of the unit during these demand occurrences. The minimum required amperes and duration ensures that these requirements can be satisfied.

The Frequency is acceptable given the administrative controls existing to ensure adequate charger performance during these 24 month intervals. In addition, this Frequency is intended to be consistent with expected fuel cycle lengths.

SR 3.8.4.7 A battery service test is a special test of the battery's capability, as found, to satisfy the design requirements (battery duty cycle) of the DC electrical power system. The test can be performed using simulated or actual loads. The discharge rate and test length corresponds to the design duty cycle requirements as specified in Reference 1.

(continued)

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DC SourcesOperating B 3.8.4 BASES SURVEILLANCE SR 3.8.4.7 (continued)

REQUIREMENTS The Frequency of 24 months is acceptable, given unit conditions required to perform the test and the other requirements existing to ensure adequate battery performance during these 24 month intervals. In addition, this Frequency is intended to be consistent with expected fuel cycle lengths.

The Frequency may be based This SR is modified by a Note. The Note allows the on factors such as operating performance of a modified performance discharge test in lieu experience, equipment reliability, of a service test provided the modified performance or plant risk, and is controlled discharge test completely envelopes the service test. This under the Surveillance substitution is acceptable because a modified performance Frequency Control Program.

test represents a more severe test of battery capacity than SR 3.8.4.7.

SR 3.8.4.8 A battery performance discharge test is a test of constant current capacity of a battery, normally done in the as found condition, after having been in service, to detect any change in the capacity determined by the acceptance test.

The test is intended to determine overall battery degradation due to age and usage.

A battery modified performance discharge test is a simulated duty cycle normally consisting of just two rates; the one minute rate published for the battery or the largest current load of the duty cycle, followed by the test rate employed for the performance discharge test, both of which envelope the duty cycle of the service test. (The test can consist of a single rate if the test rate employed for the performance discharge test exceeds the 1 minute rate and continues to envelope the duty cycle of the service test.)

Since the ampere-hours removed by a rated one minute discharge represents a very small portion of the battery capacity, the test rate can be changed to that for the performance test without compromising the results of the performance discharge test. The battery terminal voltage for the modified performance discharge test should remain above the minimum battery terminal voltage specified in the battery service test for the duration of time equal to that of the service test.

(continued)

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DC SourcesOperating B 3.8.4 BASES SURVEILLANCE SR 3.8.4.8 (continued)

REQUIREMENTS A modified performance discharge test is a test of the battery capacity and its ability to provide a high rate, short duration load (usually the highest rate of the duty cycle). This will often confirm the battery's ability to meet the critical period of the load duty cycle, in addition to determining its percentage of rated capacity. Initial conditions for the modified performance discharge test should be identical to those specified for a service test when the modified performance discharge test is performed in lieu of the service test. Either the battery performance discharge test or the modified performance discharge test is acceptable for satisfying SR 3.8.4.8; however, only the modified performance discharge test may be used to satisfy SR 3.8.4.8 while satisfying the requirements of SR 3.8.4.7 at the same time.

For the 125 VDC battery, the acceptance criteria for this Surveillance is consistent with IEEE-450 (Ref. 7) and IEEE-485 (Ref. 9). These references recommend that the battery be replaced if its capacity is below 80% of the manufacturer's rating, since IEEE-485 (Ref. 9) recommends using an aging factor of 125% in the battery size The Frequency may be based calculation. A capacity of 80% shows that the battery rate on factors such as operating of deterioration is increasing, even if there is ample experience, equipment reliability, capacity to meet the load requirements. However, since the or plant risk, and is controlled under the Surveillance 250 VDC batteries are not sized consistent with IEEE-485 Frequency Control Program. (Ref. 9), they must be replaced when their actual capacity is below the minimum acceptable battery capacity based on the load profile, which is a value greater than 80% of the manufacturer's rating.

The Frequency for this test is normally 60 months. If the battery shows degradation, or if the battery has reached 85%

of its expected life and capacity is < 100% of the manufacturer's rating, the Surveillance Frequency is reduced to 12 months. However, if the battery shows no degradation but has reached 85% of its expected life, the Surveillance Frequency is only reduced to 24 months for batteries that retain capacity 100% of the manufacturer's rating.

Degradation is indicated, consistent with IEEE-450 (Ref. 7),

when the battery capacity drops by more than 10% relative to its capacity on the previous performance test or when it is (continued)

Quad Cities 1 and 2 B 3.8.4-14 Revision 0

DC SourcesOperating B 3.8.4 BASES SURVEILLANCE SR 3.8.4.8 (continued)

REQUIREMENTS 10% below the manufacturer's rating. The 12 month and Frequency is 60 month Frequencies are consistent with the recommendations in IEEE-450 (Ref. 7). The 24 month Frequency is derived from the recommendations of IEEE-450 (Ref. 7).

REFERENCES 1. UFSAR, Section 8.3.2.

2. Safety Guide 6, March 10, 1971.

3. IEEE Standard 308, 1978.

4. UFSAR, Chapter 6.

5. UFSAR, Chapter 15.

6. Regulatory Guide 1.93, Revision 0, December 1974.

7. IEEE Standard 450, 1987.

8. Regulatory Guide 1.32, Revision 2, February 1977.

9. IEEE Standard 485, 1978.

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Battery Cell Parameters B 3.8.6 BASES ACTIONS A.1, A.2, and A.3 (continued) 7 day intervals until the parameters are restored to Category A and B limits. This periodic verification is consistent with the normal Frequency of pilot cell Surveillances.

Continued operation is only permitted for 31 days before battery cell parameters must be restored to within Category A and B limits. Taking into consideration that, while battery capacity is degraded, sufficient capacity exists to perform the intended function and to allow time to fully restore the battery cell parameters to normal limits, this time is acceptable for operation prior to declaring the associated DC batteries inoperable.

B.1 When any battery parameter is outside the Table 3.8.6-1 Category C limit for any connected cell, sufficient capacity to supply the maximum expected load requirement is not ensured and the corresponding DC electrical power subsystem must be declared inoperable. Additionally, other potentially extreme conditions, such as any Required Action of Condition A and associated Completion Time not met or average electrolyte temperature of representative cells 65°F, also are cause for immediately declaring the associated DC electrical power subsystem inoperable.

SURVEILLANCE SR 3.8.6.1 REQUIREMENTS This SR verifies that Table 3.8.6-1 Category A battery cell parameters are consistent with IEEE450 (Ref. 3), which recommends regular battery inspections (at least one per month) including voltage, specific gravity, and electrolyte level of pilot cells.

The Frequency may be based This SR verifies that Table 3.8.6-1 Category B on factors such as operating battery cell parameters including experience, equipment reliability, or plant risk, and is controlled SR 3.8.6.2 are under the Surveillance Frequency Control Program. The quarterly inspection of specific gravity, voltage, and electrolyte level for each connected cell is consistent with IEEE450 (Ref. 3). In addition, within 7 days of a battery discharge < 105 V for a 125 V battery and < 210 V for a (continued)

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Battery Cell Parameters B 3.8.6 BASES SURVEILLANCE SR 3.8.6.2 (continued)

REQUIREMENTS 250 V battery or a battery overcharge > 150 V for a 125 V battery and > 300 V for a 250 V battery, the battery must be demonstrated to meet Table 3.8.6-1 Category B limits.

Transients, such as motor starting transients, which may momentarily cause battery voltage to drop to < 105 V or

< 210 V, as applicable, do not constitute a battery discharge provided the battery terminal voltage and float current return to pre-transient values. This inspection is also consistent with IEEE450 (Ref. 3), which recommends special inspections following a severe discharge or overcharge, to ensure that no significant degradation of the battery occurs as a consequence of such discharge or overcharge. The 7 day requirement is based on engineering judgement.

SR 3.8.6.3 This Surveillance verification that the average temperature of representative cells is within limits is consistent with a recommendation of IEEE450 (Ref. 3) that states that the The Frequency may be based temperature of electrolytes in representative cells should on factors such as operating be determined on a quarterly basis. For this SR, a check of experience, equipment reliability, or plant risk, and is controlled 10% of the connected cells is considered representative.

under the Surveillance Frequency Control Program. Lower than normal temperatures act to inhibit or reduce battery capacity. This SR ensures that the operating temperatures remain within an acceptable operating range.

This limit is based on manufacturer's recommendations and the battery sizing calculation.

Table 3.8.61 This Table delineates the limits on electrolyte level, float voltage, and specific gravity for three different categories. The meaning of each category is discussed below.

Category A defines the normal parameter limit for each designed pilot cell in each battery. The cells selected as pilot cells are those whose temperature, voltage, and electrolyte specific gravity approximate the state of charge of the entire battery.

(continued)

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Distribution SystemsOperating B 3.8.7 BASES ACTIONS E.1 (continued)

Condition E corresponds to a level of degradation in the electrical power distribution system that causes a required safety function to be lost. When the inoperability of two or more AC or DC electrical power distribution subsystems, in combination, results in the loss of a required function, the plant is in a condition outside the accident analysis.

Therefore, no additional time is justified for continued operation. LCO 3.0.3 must be entered immediately to commence a controlled shutdown. The term "in combination" means that the loss of function must result from the inoperability of two or more AC and DC electrical power distribution subsystems; a loss of function solely due to a single AC or DC electrical power distribution subsystem inoperability even with another AC or DC electrical power distribution subsystem concurrently inoperable, does not require entry into Condition E.

SURVEILLANCE SR 3.8.7.1 REQUIREMENTS This Surveillance verifies that the AC and DC electrical The Frequency may be based power distribution subsystems are functioning properly, with on factors such as operating the correct circuit breaker alignment. The correct breaker experience, equipment reliability, alignment ensures the appropriate separation and or plant risk, and is controlled independence of the electrical divisions are maintained, and under the Surveillance Frequency Control Program. the appropriate voltage is available to each required bus.

The verification of proper voltage availability on the buses ensures that the required voltage is readily available for motive as well as control functions for critical system loads connected to these buses. The 7 day Frequency takes into account the redundant capability of the AC and DC electrical power distribution subsystems, redundant power supplies available to the essential service and instrument 120 VAC buses, and other indications available in the control room that alert the operator to bus and subsystem malfunctions.

REFERENCES 1. UFSAR, Chapter 6.

2. UFSAR, Chapter 15.

3. Regulatory Guide 1.93, December 1974.

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Distribution SystemsShutdown B 3.8.8 BASES ACTIONS A.1, A.2.1, A.2.2, A.2.3, A.2.4, and A.2.5 (continued) movement of recently irradiated fuel assemblies in the secondary containment, and any activities that could result in inadvertent draining of the reactor vessel).

Suspension of these activities shall not preclude completion of actions to establish a safe conservative condition.

These actions minimize the probability of the occurrence of postulated events. It is further required to immediately initiate action to restore the required AC and DC electrical power distribution subsystems and to continue this action until restoration is accomplished in order to provide the necessary power to the plant safety systems.

Notwithstanding performance of the above conservative Required Actions, a required residual heat removal-shutdown cooling (RHR-SDC) subsystem may be inoperable. In this case, Required Actions A.2.1 through A.2.4 do not adequately address the concerns relating to coolant circulation and heat removal. Pursuant to LCO 3.0.6, the RHR-SDC ACTIONS would not be entered. Therefore, Required Action A.2.5 is provided to direct declaring RHR-SDC inoperable, which results in taking the appropriate RHR-SDC ACTIONS.

The Completion Time of immediately is consistent with the required times for actions requiring prompt attention. The restoration of the required distribution subsystems should be completed as quickly as possible in order to minimize the time the plant safety systems may be without power.

SURVEILLANCE SR 3.8.8.1 REQUIREMENTS The Frequency may be based This Surveillance verifies that the required AC and DC on factors such as operating electrical power distribution subsystems are functioning experience, equipment reliability, properly, with the buses energized. The verification of or plant risk, and is controlled proper voltage availability on the buses ensures that the under the Surveillance Frequency Control Program.

required power is readily available for motive as well as control functions for critical system loads connected to these buses. The 7 day Frequency takes into account the redundant capability of the electrical power distribution subsystems, as well as other indications available in the control room that alert the operator to subsystem malfunctions.

(continued)

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Refueling Equipment Interlocks B 3.9.1 BASES SURVEILLANCE SR 3.9.1.1 (continued)

REQUIREMENTS The Frequency may be based single contact of the relay. This clarifies what is an on factors such as operating acceptable CHANNEL FUNCTIONAL TEST of a relay. This is experience, equipment reliability, acceptable because all of the other required contacts of the or plant risk, and is controlled relay are verified by other Technical Specifications and under the Surveillance non-Technical Specifications tests at least once per Frequency Control Program.

refueling interval with applicable extensions.

The 7 day Frequency is based on engineering judgment and is considered adequate in view of other indications of refueling interlocks and their associated input status that are available to unit operations personnel.

REFERENCES 1. UFSAR, Sections 3.1.5.3 and 3.1.5.4.

2. UFSAR, Section 7.7.1.2.2.

3. UFSAR, Section 15.4.1.

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Refuel Position One-Rod-Out Interlock B 3.9.2 BASES ACTIONS A.1 and A.2 (continued) control rods are fully inserted. Control rods in core cells containing no fuel assemblies do not affect the reactivity of the core and, therefore, do not have to be inserted.

SURVEILLANCE SR 3.9.2.1 REQUIREMENTS Proper functioning of the refueling position one-rod-out interlock requires the reactor mode switch to be in Refuel.

During control rod withdrawal in MODE 5, improper positioning of the reactor mode switch could, in some instances, allow improper bypassing of required interlocks.

Therefore, this Surveillance imposes an additional level of assurance that the refueling position one-rod-out interlock will be OPERABLE when required. By "locking" the reactor mode switch in the proper position, an additional administrative control is in place to preclude operator errors from resulting in unanalyzed operation.

The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is sufficient in view of other administrative controls utilized during refueling operations to ensure safe operation.

SR 3.9.2.2 Performance of a CHANNEL FUNCTIONAL TEST on each channel demonstrates the associated refuel position one-rod-out interlock will function properly when a simulated or actual signal indicative of a required condition is injected into the logic. A successful test of the required contact(s) of a channel relay may be performed by the verification of the The Frequency may be based change of state of a single contact of the relay. This on factors such as operating clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a experience, equipment reliability, relay. This is acceptable because all of the other required or plant risk, and is controlled under the Surveillance contacts of the relay are verified by other Technical Frequency Control Program. Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. The 7 day Frequency is considered adequate because of demonstrated circuit reliability, procedural (continued)

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Refuel Position One-Rod-Out Interlock B 3.9.2 BASES SURVEILLANCE SR 3.9.2.2 (continued)

REQUIREMENTS controls on control rod withdrawals, and visual indications available in the control room to alert the operator to control rods not fully inserted. To perform the required testing, the applicable condition must be entered (i.e., a control rod must be withdrawn from its full-in position).

Therefore, SR 3.9.2.2 has been modified by a Note that states the CHANNEL FUNCTIONAL TEST is not required to be performed until 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after any control rod is withdrawn.

REFERENCES 1. UFSAR, Sections 3.1.5.3 and 3.1.5.4.

2. UFSAR, Section 7.7.1.2.1.

3. UFSAR, Section 15.4.1.

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Control Rod Position B 3.9.3 BASES SURVEILLANCE SR 3.9.3.1 (continued)

REQUIREMENTS The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency takes into consideration the procedural controls on control rod movement during refueling as well as the redundant functions of the refueling interlocks.

REFERENCES 1. UFSAR, Sections 3.1.5.3 and 3.1.5.4.

2. UFSAR, Section 15.4.1.

The Frequency may be based on factors such as operating experience, equipment reliability, or plant risk, and is controlled under the Surveillance Frequency Control Program.

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Control Rod OPERABILITYRefueling B 3.9.5 BASES SURVEILLANCE SR 3.9.5.1 and SR 3.9.5.2 (continued)

REQUIREMENTS The 7 day Frequency takes into consideration equipment reliability, procedural controls over the scram accumulators, and control room alarms and indicating lights that indicate low accumulator charge pressures.

The Frequency may be based SR 3.9.5.1 is modified by a Note that allows 7 days after on factors such as operating withdrawal of the control rod to perform the Surveillance.

experience, equipment reliability, This acknowledges that the control rod must first be or plant risk, and is controlled withdrawn before performance of the Surveillance, and under the Surveillance Frequency Control Program. therefore avoids potential conflicts with SR 3.0.1.

REFERENCES 1. UFSAR, Sections 3.1.5.3 and 3.1.5.4.

2. UFSAR, Section 15.4.1.

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RPV Water LevelIrradiated Fuel B 3.9.6 BASES (continued)

SURVEILLANCE SR 3.9.6.1 REQUIREMENTS Verification of a minimum water level of 23 ft above the top of the RPV flange ensures that the design basis for the The Frequency may be based postulated fuel handling accident analysis during refueling on factors such as operating operations is met. Water at the required level limits the experience, equipment reliability, consequences of damaged fuel rods, which are postulated to or plant risk, and is controlled result from a fuel handling accident in containment under the Surveillance (Ref. 2).

Frequency Control Program.

The Frequency of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is based on engineering judgment and is considered adequate in view of the large volume of water and the normal procedural controls on valve positions, which make significant unplanned level changes unlikely.

REFERENCES 1. Regulatory Guide 1.183, July 2000.

2. UFSAR, Section 15.7.2.

3. 10 CFR 50.67.

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RPV Water LevelNew Fuel or Control Rods B 3.9.7 BASES SURVEILLANCE SR 3.9.7.1 (continued)

REQUIREMENTS The Frequency of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is based on engineering judgment and is considered adequate in view of the large volume of water and the normal procedural controls on valve positions, which make significant unplanned level changes unlikely.

REFERENCES 1. Regulatory Guide 1.183, July 2000.

2. UFSAR, Section 15.7.2.

3. 10 CFR 50.67.

The Frequency may be based on factors such as operating experience, equipment reliability, or plant risk, and is controlled under the Surveillance Frequency Control Program.

Quad Cities 1 and 2 B 3.9.7-3 Revision 31

RHRHigh Water Level B 3.9.8 BASES ACTIONS B.1, B.2, B.3, and B.4 (continued) secondary containment isolation valve and associated instrumentation are OPERABLE or other acceptable administrative controls to assure isolation capability.

These administrative controls consist of stationing a dedicated operator, who is in continuous communication with the control room, at the controls of the isolation device.

In this way, the penetration can be rapidly isolated when a need for secondary containment isolation is indicated).

This may be performed as an administrative check, by examining logs or other information to determine whether the components are out of service for maintenance or other reasons. It is not necessary to perform the Surveillances needed to demonstrate the OPERABILITY of the components.

If, however, any required component is inoperable, then it must be restored to OPERABLE status. In this case, a surveillance may need to be performed to restore the component to OPERABLE status. Actions must continue until all required components are OPERABLE.

SURVEILLANCE SR 3.9.8.1 REQUIREMENTS Periodic monitoring of reactor coolant temperature ensures the need to establish decay heat removal, to maintain or reduce the reactor coolant temperature, is identified in a timely manner. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Frequency is based on the importance of the decay heat removal and coolant circulation function.

The Frequency may be based on factors such as operating SR 3.9.8.2 experience, equipment reliability, or plant risk, and is controlled under the Surveillance Verifying the correct alignment for manual and power Frequency Control Program. operated valves in the RHR shutdown cooling flow path provides assurance that the proper flow paths will exist for RHR operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these were verified to be in the correct position prior to locking, sealing, or securing. A valve that can be manually (from the control room or locally) aligned is allowed to be in a non-RHR shutdown cooling position provided the valve can be repositioned. This SR does not require any testing (continued)

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RHRHigh Water Level B 3.9.8 BASES SURVEILLANCE SR 3.9.8.2 (continued)

REQUIREMENTS The Frequency may be based or valve manipulation; rather, it involves verification that on factors such as operating those valves capable of potentially being mispositioned are experience, equipment reliability, in the correct position. This SR does not apply to valves or plant risk, and is controlled that cannot be inadvertently misaligned, such as check under the Surveillance valves.

Frequency Control Program.

The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is sufficient in view of other visual and audible indications available to the operator for monitoring the RHR shutdown cooling subsystem in the control room.

REFERENCES 1. UFSAR, Section 5.4.7.

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RHRLow Water Level B 3.9.9 BASES ACTIONS B.1, B.2, and B.3 (continued)

With the required decay heat removal subsystem(s) inoperable and the required alternate method(s) of decay heat removal not available in accordance with Required Action A.1, additional actions are required to minimize any potential fission product release to the environment. This includes ensuring secondary containment is OPERABLE; one standby gas treatment subsystem is OPERABLE; and secondary containment isolation capability is available in each associated penetration flow path not isolated that is assumed to be isolated to mitigate radioactive releases (i.e., one secondary containment isolation valve and associated instrumentation are OPERABLE or other acceptable administrative controls to assure isolation capability.

These administrative controls consist of stationing a dedicated operator, who is in continuous communication with the control room, at the controls of the isolation device.

In this way, the penetration can be rapidly isolated when a need for secondary containment isolation is indicated).

This may be performed as an administrative check, by examining logs or other information to determine whether the components are out of service for maintenance or other reasons. It is not necessary to perform the Surveillances needed to demonstrate the OPERABILITY of the components.

If, however, any required component is inoperable, then it must be restored to OPERABLE status. In this case, the surveillance may need to be performed to restore the component to OPERABLE status. Actions must continue until all required components are OPERABLE.

SURVEILLANCE SR 3.9.9.1 REQUIREMENTS Periodic monitoring of reactor coolant temperature ensures the need to establish decay heat removal, to maintain or reduce the reactor coolant temperature, is identified in a timely manner. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Frequency is based on the importance of the decay heat removal and coolant circulation function.

(continued)

The Frequency may be based on factors such as operating experience, equipment reliability, or plant risk, and is controlled under the Surveillance Frequency Control Program.

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RHRLow Water Level B 3.9.9 BASES SURVEILLANCE SR 3.9.9.2 REQUIREMENTS (continued) Verifying the correct alignment for manual and power operated valves in the required RHR shutdown cooling flow paths provides assurance that the proper flow paths will exist for RHR operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these were verified to be in the correct position prior to locking, sealing, or securing. A valve that can be manually (from the control room or locally) aligned is allowed to be in a non-RHR shutdown cooling position The Frequency may be based provided the valve can be repositioned. This SR does not on factors such as operating require any testing or valve manipulation; rather, it experience, equipment reliability, involves verification that those valves capable of or plant risk, and is controlled potentially being mispositioned are in the correct position.

under the Surveillance This SR does not apply to valves that cannot be Frequency Control Program.

inadvertently misaligned, such as check valves.

The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is sufficient in view of other visual and audible indications available to the operator for monitoring the RHR subsystems in the control room.

REFERENCES 1. UFSAR, Section 5.4.7.

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Reactor Mode Switch Interlock Testing B 3.10.1 BASES SURVEILLANCE SR 3.10.1.1 and SR 3.10.1.2 (continued)

REQUIREMENTS The Frequency may be based The administrative controls are to be periodically verified on factors such as operating to ensure that the operational requirements continue to be experience, equipment reliability, met. In addition, the all rods fully inserted Surveillance or plant risk, and is controlled (SR 3.10.1.1) must be verified by a second licensed operator under the Surveillance (Reactor Operator or Senior Reactor Operator) or other task Frequency Control Program.

qualified member of the technical staff (e.g., a shift technical advisor or reactor engineer). The Surveillances performed at the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequencies are intended to provide appropriate assurance that each operating shift is aware of and verifies compliance with these Special Operations LCO requirements.

REFERENCES 1. UFSAR, Chapter 7.2.

2. UFSAR, Section 15.4.1.

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Single Control Rod WithdrawalHot Shutdown B 3.10.2 BASES ACTIONS A.1 (continued) been added, which clarifies that this Required Action is only applicable if the requirements not met are for an affected LCO.

A.2.1 and A.2.2 Required Actions A.2.1 and A.2.2 are alternate Required Actions that can be taken instead of Required Action A.1 to restore compliance with the normal MODE 3 requirements, thereby exiting this Special Operations LCO's Applicability.

Actions must be initiated immediately to insert all insertable control rods. Actions must continue until all such control rods are fully inserted. Placing the reactor mode switch in the shutdown position will ensure all inserted rods remain inserted and restore operation in accordance with Table 1.1-1. The allowed Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months to place the reactor mode switch in the shutdown position provides sufficient time to normally insert the control rods.

SURVEILLANCE SR 3.10.2.1, SR 3.10.2.2, and SR 3.10.2.3 REQUIREMENTS The other LCOs made applicable in this Special Operations LCO are required to have their Surveillances met to establish that this Special Operations LCO is being met. If the local array of control rods is inserted and disarmed while the scram function for the withdrawn rod is not available, periodic verification in accordance with SR 3.10.2.2 is required to preclude the possibility of criticality. The control rods can be hydraulically disarmed by closing the drive water and exhaust water isolation valves. Electrically, the control rods can be disarmed by disconnecting power from all four directional control valve The Frequency may be based solenoids. SR 3.10.2.2 has been modified by a Note, which on factors such as operating clarifies that this SR is not required to be met if experience, equipment reliability, SR 3.10.2.1 is satisfied for LCO 3.10.2.d.1 requirements, or plant risk, and is controlled under the Surveillance since SR 3.10.2.2 demonstrates that the alternative Frequency Control Program. LCO 3.10.2.d.2 requirements are satisfied. Also, SR 3.10.2.3 verifies that all control rods other than the control rod being withdrawn are fully inserted. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is acceptable because of the administrative (continued)

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Single Control Rod WithdrawalHot Shutdown B 3.10.2 BASES SURVEILLANCE SR 3.10.2.1, SR 3.10.2.2, and SR 3.10.2.3 (continued)

REQUIREMENTS controls on control rod withdrawal, the protection afforded by the LCOs involved, and hardwire interlocks that preclude additional control rod withdrawals.

REFERENCES 1. UFSAR, Section 15.4.1.

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Single Control Rod WithdrawalCold Shutdown B 3.10.3 BASES (continued)

SURVEILLANCE SR 3.10.3.1, SR 3.10.3.2, SR 3.10.3.3, and SR 3.10.3.4 REQUIREMENTS The other LCOs made applicable by this Special Operations LCO are required to have their associated surveillances met to establish that this Special Operations LCO is being met.

If the local array of control rods is inserted and disarmed while the scram function for the withdrawn rod is not available, periodic verification is required to ensure that the possibility of criticality remains precluded. The control rods can be hydraulically disarmed by closing the drive water and exhaust water isolation valves.

Electrically, the control rods can be disarmed by disconnecting power from all four directional control valve The Frequency may be based solenoids. Verification that all the other control rods are on factors such as operating fully inserted is required to meet the SDM requirements.

experience, equipment reliability, Verification that a control rod withdrawal block has been or plant risk, and is controlled inserted ensures that no other control rods can be under the Surveillance inadvertently withdrawn under conditions when position Frequency Control Program.

indication instrumentation is inoperable for the affected control rod. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is acceptable because of the administrative controls on control rod withdrawals, the protection afforded by the LCOs involved, and hardwire interlocks to preclude an additional control rod withdrawal.

SR 3.10.3.2 and SR 3.10.3.4 have been modified by Notes, which clarify that these SRs are not required to be met if the alternative requirements demonstrated by SR 3.10.3.1 are satisfied.

REFERENCES 1. UFSAR, Section 15.4.1.

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Single CRD RemovalRefueling B 3.10.4 BASES SURVEILLANCE SR 3.10.4.1, SR 3.10.4.2, SR 3.10.4.3, SR 3.10.4.4, REQUIREMENTS and SR 3.10.4.5 (continued)

Periodic verification of the administrative controls established by this Special Operations LCO is prudent to preclude the possibility of an inadvertent criticality. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is acceptable, given the administrative controls on control rod removal and hardwire interlock to block an additional control rod withdrawal.

REFERENCES 1. UFSAR, Section 15.4.1.

The Frequency may be based on factors such as operating experience, equipment reliability, or plant risk, and is controlled under the Surveillance Frequency Control Program.

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Multiple Control Rod WithdrawalRefueling B 3.10.5 BASES APPLICABILITY Operations LCO are appropriately controlled by requiring all (continued) fuel to be removed from cells whose "full-in" indicators are allowed to be bypassed.

ACTIONS A.1, A.2, A.3.1, and A.3.2 If one or more of the requirements of this Special Operations LCO are not met, the immediate implementation of these Required Actions restores operation consistent with the normal requirements for refueling (i.e., all control rods inserted in core cells containing one or more fuel assemblies) or with the exceptions granted by this Special Operations LCO. The Completion Times for Required Action A.1, Required Action A.2, Required Action A.3.1, and Required Action A.3.2 are intended to require that these Required Actions be implemented in a very short time and carried through in an expeditious manner to either initiate action to restore the affected CRDs and insert their control rods, or initiate action to restore compliance with this Special Operations LCO.

SURVEILLANCE SR 3.10.5.1, SR 3.10.5.2, and SR 3.10.5.3 REQUIREMENTS Periodic verification of the administrative controls established by this Special Operations LCO is prudent to preclude the possibility of an inadvertent criticality. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is acceptable, given the administrative controls on fuel assembly and control rod removal, and takes into account other indications of control rod status available in the control room.

REFERENCES 1. UFSAR, Section 15.4.1.

The Frequency may be based on factors such as operating experience, equipment reliability, or plant risk, and is controlled under the Surveillance Frequency Control Program.

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SDM TestRefueling B 3.10.7 BASES (continued)

SURVEILLANCE SR 3.10.7.1, SR 3.10.7.2, and SR 3.10.7.3 REQUIREMENTS LCO 3.3.1.1, Functions 2.a and 2.d, made applicable in this Special Operations LCO, are required to have applicable Surveillances met to establish that this Special Operations LCO is being met (SR 3.10.7.1). However, the control rod withdrawal sequences during the SDM tests may be enforced by the RWM (LCO 3.3.2.1, Function 2, MODE 2 requirements) or by a second licensed operator (Reactor Operator or Senior Reactor Operator) or other task qualified member of the technical staff (e.g., a shift technical advisor or reactor engineer). As noted, either the applicable SRs for the RWM (LCO 3.3.2.1) must be satisfied according to the applicable Frequencies (SR 3.10.7.2), or the proper movement of control rods must be verified (SR 3.10.7.3). This latter verification (i.e., SR 3.10.7.3) must be performed during control rod movement to prevent deviations from the The Frequency may be based specified sequence. These surveillances provide adequate on factors such as operating experience, equipment reliability, assurance that the specified test sequence is being or plant risk, and is controlled followed.

under the Surveillance Frequency Control Program.

SR 3.10.7.4 Periodic verification of the administrative controls established by this LCO will ensure that the reactor is operated within the bounds of the safety analysis. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is intended to provide appropriate assurance that each operating shift is aware of and verifies compliance with these Special Operations LCO requirements.

SR 3.10.7.5 Coupling verification is performed to ensure the control rod is connected to the control rod drive mechanism and will perform its intended function when necessary. The verification is required to be performed any time a control rod is withdrawn to the "full-out" notch position, or prior to declaring the control rod OPERABLE after work on the control rod or CRD System that could affect coupling. This Frequency is acceptable, considering the low probability that a control rod will become uncoupled when it is not being moved as well as operating experience related to uncoupling events.

(continued)

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SDM TestRefueling B 3.10.7 BASES SURVEILLANCE SR 3.10.7.6 REQUIREMENTS (continued) CRD charging water header pressure verification is performed to ensure the motive force is available to scram the control rods in the event of a scram signal. Since the reactor is The Frequency may be based depressurized in MODE 5, there is insufficient reactor on factors such as operating pressure to scram the control rods. Verification of experience, equipment reliability, charging water header pressure ensures that if a scram were or plant risk, and is controlled required, capability for rapid control rod insertion would under the Surveillance exist. The minimum pressure of 940 psig is well below the Frequency Control Program.

expected pressure of approximately 1500 psig while still ensuring sufficient pressure for rapid control rod insertion. The 7 day Frequency has been shown to be acceptable through operating experience and takes into account indications available in the control room.

REFERENCES 1. UFSAR, Section 15.4.10.

2. XN-NF-80-19(P)(A), Volume 1, Supplement 2, Section 7.1, Exxon Nuclear Methodology for Boiling Water Reactor Neutronics Methods for Design Analysis, (as specified in Technical Specification 5.6.5).

3. NEDE-24011-P-A-US, General Electric Standard Application for Reactor Fuel, (as specified in Technical Specification 5.6.5).

4. Letter from T. Pickens (BWROG) to G.C. Lainas, NRC, "Amendment 17 to General Electric Licensing Topical Report NEDE-24011-P-A," BWROG-8644, August 15, 1986.

5. NFSR-0091, Benchmark of CASMO/MICROBURN BWR Nuclear Design Methods, Commonwealth Edison Topical Report, (as specified in Technical Specification 5.6.5).

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ATTACHMENT 5 TSTF-425 (NUREG-1433) vs. QCNPS Cross-Reference Technical Specification Section Title/Surveillance Description* TSTF-425 QCNPS Control Rod Operability 3.1.3 3.1.3 Control rod position 3.1.3.1 3.1.3.1 Notch test - fully withdrawn control rod one notch 3.1.3.2 3.1.3.3 Notch test - partially withdrawn control rod one notch 3.1.3.3 3.1.3.3 Control Rod Scram Times 3.1.4 3.1.4 Scram time testing 3.1.4.2 3.1.4.2 Control Rod Scram Accumulators 3.1.5 3.1.5 Control rod scram accumulator pressure 3.1.5.1 3.1.5.1 Rod Pattern Control 3.1.6 3.1.6 Analyzed rod position sequence 3.1.6.1 3.1.6.1 Standby Liquid Control (SLC) System 3.1.7 3.1.7 Volume of sodium pentaborate [Level of pentaborate in SLC tank] 3.1.7.1 3.1.7.1 Temperature of sodium pentaborate solution 3.1.7.2 3.1.7.2 Temperature of pump suction piping 3.1.7.3 3.1.7.3 Continuity of explosive charge 3.1.7.4 3.1.7.4 Concentration of boron solution 3.1.7.5 3.1.7.5 Manual/power operated valve position 3.1.7.6 3.1.7.6 Pump flow rate 3.1.7.7 3.1.7.7**

Flow through one SLC subsystem 3.1.7.8 3.1.7.8 Heat traced piping is unblocked 3.1.7.9 3.1.7.9 Scram Discharge Volume (SDV) Vent & Drain Valves 3.1.8 3.1.8 Each SDV vent & drain valve open 3.1.8.1 3.1.8.1 Cycle each SDV vent & drain valve fully closed/fully open position 3.1.8.2 3.1.8.2 Each SDV vent & drain valve closes on receipt of scram 3.1.8.3 3.1.8.3 Average Planar Linear Heat Generation Rate (APLHGR) 3.2.1 3.2.1 APLHGR less than or equal to limits 3.2.1.1 3.2.1.1 Minimum Critical Power Ratio (MCPR) 3.2.2 3.2.2 MCPR greater than or equal to limits 3.2.2.1 3.2.2.1 Linear Heat Generation Rate (LHGR) 3.2.3 3.2.3 LHGR less than or equal to limits 3.2.3.1 3.2.3.1 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 3.3.1.1 Channel Check 3.3.1.1.1 3.3.1.1.1 Absolute diff. between APRM channels & calculated power 3.3.1.1.2 3.3.1.1.2 Adjust channel to conform to calibrated flow (APRM STP - Hi) 3.3.1.1.3 3.3.1.1.3 Channel Functional Test (after entering Mode 2) 3.3.1.1.4 3.3.1.1.4 Channel Functional Test 3.3.1.1.5 3.3.1.1.5 3.3.1.1.8 IRM/APRM channel overlap ------------ 3.3.1.1.7 Calibrate local power range monitors 3.3.1.1.6 3.3.1.1.9 Channel Functional Test (quarterly) 3.3.1.1.7 3.3.1.1.10 Calibrate trip units (quarterly) 3.3.1.1.8 3.3.1.1.11 Channel Calibration (Drywell Pressure - High and Turbine --------- 3.3.1.1.12 Condenser Vacuum - Lo) (Quarterly)

Channel Calibration (184 days) 3.3.1.1.9 3.3.1.1.14 Page 1 of 10

ATTACHMENT 5 TSTF-425 (NUREG-1433) vs. QCNPS Cross-Reference Technical Specification Section Title/Surveillance Description* TSTF-425 QCNPS Channel Functional Test (Reactor Mode Switch ) 3.3.1.1.10 3.3.1.1.15 Channel Calibration 3.3.1.1.11 3.3.1.1.16 Verify APRM Flow Biased STP - High 3.3.1.1.12 ---------

Logic System Functional Test 3.3.1.1.13 3.3.1.1.17 Verify TSV/TCV closure/Trip Oil Press-Low Not Bypassed 3.3.1.1.14 3.3.1.1.13 Verify RPS Response Time 3.3.1.1.15 3.3.1.1.18 Source Range Monitor (SRM) Instrumentation 3.3.1.2 3.3.1.2 Channel Check 3.3.1.2.1 3.3.1.2.1 Verify Operable SRM Detector 3.3.1.2.2 3.3.1.2.2 Channel Check 3.3.1.2.3 3.3.1.2.3 Verify count rate 3.3.1.2.4 3.3.1.2.4 Channel Functional Test (Mode 5) (7 days) 3.3.1.2.5 3.3.1.2.5 Channel Functional Test (Modes 2, 3, 4) (31 days) 3.3.1.2.6 3.3.1.2.6 Channel Calibration 3.3.1.2.7 3.3.1.2.7 OPRM Instrumentation ------------ 3.3.1.3 Channel Functional Test ------------ 3.3.1.3.1 Calibrate LPRMs ------------ 3.3.1.3.2 Channel Calibration ------------ 3.3.1.3.3 Logic System Functional Test ------------ 3.3.1.3.4 Verify OPRM not bypassed ------------ 3.3.1.3.5 Verify RPS Response Time ------------ 3.3.1.3.6 Control Rod Block Instrumentation 3.3.2.1 3.3.2.1 Channel Functional Test (routine) 3.3.2.1.1 3.3.2.1.1 Channel Functional Test (rod withdrawal at < 10% RTP) 3.3.2.1.2 3.3.2.1.2 Channel Functional Test (thermal power < 10%) 3.3.2.1.3 3.3.2.1.3 Verify RBM not bypassed 3.3.2.1.4 3.3.2.1.5 Verify RWM not bypassed (thermal power < 10%) 3.3.2.1.5 3.3.2.1.6 Channel Functional Test 3.3.2.1.6 3.3.2.1.7 Channel Calibration 3.3.2.1.7 3.3.2.1.4 Feedwater & Main Turbine High Water Level Trip Instrumentation 3.3.2.2 3.3.2.2 Channel Check 3.3.2.2.1 3.3.2.2.1 Channel Functional Test 3.3.2.2.2 3.3.2.2.2 Calibrate trip unit --------- 3.3.2.2.3 Channel Calibration 3.3.2.2.3 3.3.2.2.4 Logic System Functional Test 3.3.2.2.4 3.3.2.2.5 Post Accident Monitor (PAM) Instrumentation 3.3.3.1 3.3.3.1 Channel Check 3.3.3.1.1 3.3.3.1.1 Calibration 3.3.3.1.2 3.3.3.1.2 Remote Shutdown System 3.3.3.2 ------

Channel Check 3.3.3.2.1 ---------

Verify control circuit and transfer switch capable of function 3.3.3.2.2 ---------

Channel Calibration 3.3.3.2.3 ---------

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 ---------

Page 2 of 10

ATTACHMENT 5 TSTF-425 (NUREG-1433) vs. QCNPS Cross-Reference Technical Specification Section Title/Surveillance Description* TSTF-425 QCNPS 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 ---------

Determine RPT breaker interruption time 3.3.4.1.7 ---------

Anticipated Trip Without Scram-RPT Instrumentation 3.3.4.2 3.3.4.1 Channel Check 3.3.4.2.1 3.3.4.1.1 Channel Functional Test 3.3.4.2.2 3.3.4.1.3 Calibrate trip units 3.3.4.2.3 3.3.4.1.2 Channel Calibration 3.3.4.2.4 3.3.4.1.4 Logic System Functional Test 3.3.4.2.5 3.3.4.1.5 Emergency Core Cooling System (ECCS) Instrumentation 3.3.5.1 3.3.5.1 Channel Check 3.3.5.1.1 3.3.5.1.1 Channel Functional Test 3.3.5.1.2 3.3.5.1.2 Calibrate trip units 3.3.5.1.3 3.3.5.1.3 Channel Calibration (-92 days) 3.3.5.1.4 3.3.5.1.4 Channel Calibration (184 days) --------- 3.3.1.5.5 Channel Calibration ([18] months) 3.3.5.1.5 3.3.5.1.6 Logic System Functional Test 3.3.5.1.6 3.3.5.1.7 Verify ECCS Response Time 3.3.5.1.7 ---------

Reactor Core Isolation Cooling (RCIC) System Instrumentation 3.3.5.2 3.3.5.2 Channel Check 3.3.5.2.1 3.3.5.2.1 Channel Functional Test 3.3.5.2.2 3.3.5.2.3 Calibrate trip units 3.3.5.2.3 3.3.5.2.2 Channel Calibration (Condensate Storage Tank Level - Low) 3.3.5.2.4 -----------

Channel Calibration 3.3.5.2.5 3.3.5.2.4 Logic System Functional Test 3.3.5.2.6 3.3.5.2.5 Primary Containment Isolation Instrumentation 3.3.6.1 3.3.6.1 Channel Check 3.3.6.1.1 3.3.6.1.1 Channel Functional Test 3.3.6.1.2 3.3.6.1.2 Calibrate trip units 3.3.6.1.3 3.3.6.1.3 Channel Calibration 3.3.6.1.4 3.3.6.1.4 Channel Functional Test 3.3.6.1.5 3.3.6.1.5 Channel Calibration 3.3.6.1.6 3.3.6.1.6 Logic System Functional Test 3.3.6.1.7 3.3.6.1.7 Verify Isolation Response Time [Main Steam Isolation Valves] 3.3.6.1.8 ---------

Secondary Containment Isolation Instrumentation 3.3.6.2 3.3.6.2 Channel Check 3.3.6.2.1 3.3.6.2.1 Channel Functional Test 3.3.6.2.2 3.3.6.2.2 Calibrate trip units 3.3.6.2.3 3.3.6.2.3 Channel Calibration 3.3.6.2.4 3.3.6.2.4 Channel Calibration 3.3.6.2.5 3.3.6.2.5 Logic System Functional Test 3.3.6.2.6 3.3.6.2.6 Verify Isolation Response Time 3.3.6.2.7 -----------

Low-Low-Set (LLS) [QCNPS - Relief Valve] Instrumentation 3.3.6.3 3.3.6.3 Channel Check 3.3.6.3.1 -----------

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

Page 3 of 10

ATTACHMENT 5 TSTF-425 (NUREG-1433) vs. QCNPS Cross-Reference Technical Specification Section Title/Surveillance Description* TSTF-425 QCNPS 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 3.3.6.3.1 Logic System Functional Test 3.3.6.3.7 3.3.6.3.2 Main Control Room Environmental Control (MCREC) [Control 3.3.7.1 3.3.7.1 Room Area Filtration (CRAF) System] Instrumentation Channel Check 3.3.7.1.1 3.3.7.1.1 Channel Functional Test 3.3.7.1.2 3.3.7.1.2 Calibrate trip units 3.3.7.1.3 3.3.7.1.3 Channel Calibration 3.3.7.1.4 3.3.7.1.4 3.3.7.1.5 Logic System Functional Test 3.3.7.1.5 3.3.7.1.6 Mechanical Vacuum Pump Trip Instrumentation ------- 3.3.7.2 Channel Check --------- 3.3.7.2.1 Channel Functional Test --------- 3.3.7.2.2 Channel Calibration --------- 3.3.7.2.3 Channel Calibration --------- 3.3.7.2.4 Logic System Functional Test --------- 3.3.7.2.5 Loss of Power (LOP) Instrumentation 3.3.8.1 3.3.8.1 Channel Check 3.3.8.1.1 -----------

Channel Functional Test 3.3.8.1.2 3.3.8.1.1 Channel Calibration 3.3.8.1.3 3.3.8.1.2 Channel Functional Test (Loss of Voltage) ----------- 3.3.8.1.3 Channel Calibration (Loss of Voltage) ----------- 3.3.8.1.4 Logic System Functional Test 3.3.8.1.4 3.3.8.1.5 RPS Electric Power Monitoring 3.3.8.2 3.3.8.2 Channel Functional Test 3.3.8.2.1 3.3.8.2.1 Channel Calibration 3.3.8.2.2 3.3.8.2.2 System functional test 3.3.8.2.3 3.3.8.2.3 Recirculation Loops Operating 3.4.1 3.4.1 Recirc loop jet pump flow mismatch with both loops operating 3.4.1.1 3.4.1.1 Jet Pumps 3.4.2 3.4.2 Criteria satisfied for each operating recirc loop 3.4.2.1 3.4.2.1 Safety/Relief Valves (SRVs) 3.4.3 3.4.3 Safety function lift setpoints 3.4.3.1 3.4.3.1**

SRV opens [QCNPS - actuator strokes] when manually actuated 3.4.3.2 3.4.3.2 Relief valve actuates automatically -------- 3.4.3.3 Reactor Coolant System (RCS) Operational Leakage 3.4.4 3.4.4 RCS unidentified and total leakage increase within limits 3.4.4.1 3.4.4.1 RCS Pressure Isolation Valve (PIV) Leakage 3.4.5 ------

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

RCS Leakage Detection Instrumentation 3.4.6 3.4.5 Channel Check 3.4.6.1 3.4.5.1 Channel Functional Test 3.4.6.2 3.4.5.2 Channel Calibration 3.4.6.3 3.4.5.3 Page 4 of 10

ATTACHMENT 5 TSTF-425 (NUREG-1433) vs. QCNPS Cross-Reference Technical Specification Section Title/Surveillance Description* TSTF-425 QCNPS RCS Specific Activity 3.4.7 3.4.6 Dose Equivalent I-131 specific activity 3.4.7.1 3.4.6.1 Residual Heat Removal (RHR) Shutdown Cooling - Hot Shutdown 3.4.8 3.4.7 One RHR Shutdown cooling subsystem operating 3.4.8.1 ---------

Verify each flow path valve position --------- 3.4.7.1 RHR Shutdown Cooling - Cold Shutdown 3.4.9 3.4.8 One RHR Shutdown cooling subsystem operating 3.4.9.1 ----------

Verify each flow path valve position --------- 3.4.8.1 RCS Pressure/Temperature Limit 3.4.10 3.4.9 RCS pressure, temperature, heatup and cooldown rates 3.4.10.1 3.4.9.1 RPV flange/head flange temperatures (tensioning head bolt stud) 3.4.10.7 3.4.9.5 RPV flange/head flange temperatures (after RCS temp < 80oF 3.4.10.8 3.4.9.6

[QCNPS - 93°F])

RPV flange/head flange temperatures (after RCS temp < 100oF 3.4.10.9 3.4.9.7

[QCNPS - 113°F])

Reactor Steam Dome Pressure 3.4.11 3.4.10 Verify reactor steam dome pressure 3.4.11.1 3.4.10.1 ECCS - Operating 3.5.1 3.5.1 Verify injection/spray piping filled with water 3.5.1.1 3.5.1.1 Verify each valve in flow path is in correct position 3.5.1.2 3.5.1.2 Verify ADS header pressure 3.5.1.3 3.5.1.12 Verify correct breaker alignment --------- 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 3.5.1.5**

Verify HPCI flow rate (Rx press < 1020, > 920) 3.5.1.8 ---------

Verify HPCI flow rate (Rx press < 165 [180]) 3.5.1.9 3.5.1.7 Verify ECCS actuates on initiation signal 3.5.1.10 3.5.1.8 Verify ADS actuates on initiation signal 3.5.1.11 3.5.1.9 Verify each ADS valve opens [actuator strokes] when manually 3.5.1.12 3.5.1.10 actuated Verify automatic transfer capability --------- 3.5.1.11 ECCS - Shutdown 3.5.2 3.5.2 Verify, for LPCI [ECCS], suppression pool water level 3.5.2.1 3.5.2.1 Verify, for CS, suppression pool water level and CST water level 3.5.2.2 3.5.2.1 Verify ECCS piping filled with water 3.5.2.3 3.5.2.2 Verify each valve in flow path is in correct position 3.5.2.4 3.5.2.3 Verify each ECCS pump develops flow 3.5.2.5 3.5.2.4**

Verify ECCS actuates on initiation signal 3.5.2.6 3.5.2.5 RCIC System 3.5.3 3.5.3 Verify RCIC piping filled with water 3.5.3.1 3.5.3.1 Verify each valve in flow path is in correct position 3.5.3.2 3.5.3.2 Verify RCIC flow rate (Rx press <1020, >920) [QCNPS - 1005 psig, 3.5.3.3 3.5.3.3 920 psig]

Verify RCIC flow rate (Rx press < 165) [QCNPS - 180 psig] 3.5.3.4 3.5.3.4 Verify RCIC actuates on initiation signal 3.5.3.5 3.5.3.5 Page 5 of 10

ATTACHMENT 5 TSTF-425 (NUREG-1433) vs. QCNPS Cross-Reference Technical Specification Section Title/Surveillance Description* TSTF-425 QCNPS Primary Containment 3.6.1.1 3.6.1.1 Verify drywell to suppression chamber differential pressure [bypass 3.6.1.1.2 3.6.1.1.2 leakage]

Primary Containment Air Lock 3.6.1.2 3.6.1.2 Verify only one door can be opened at a time 3.6.1.2.2 3.6.1.2.2 Primary Containment Isolation Valves (PCIVs) 3.6.1.3 3.6.1.3 Verify purge valve is 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 3.6.1.3.1 Verify each manual PCIV outside containment is closed 3.6.1.3.3 3.6.1.3.2 Verify continuity of traversing incore probe (TIP) shear valve 3.6.1.3.5 3.6.1.3.4 Verify isolation time of each power operated PCIV 3.6.1.3.6 3.6.1.3.5**

Perform leakage rate testing on each PC purge valve 3.6.1.3.7 -----------

Verify isolation time of MSIVs 3.6.1.3.8 3.6.1.3.6**

Verify automatic PCIV actuates to isolation position 3.6.1.3.9 3.6.1.3.7 Verify sample of Excess Flow Check Valves actuate to isolation 3.6.1.3.10 3.6.1.3.8 position Test explosive squib from each shear valve 3.6.1.3.11 3.6.1.3.9 Verify each purge valve is blocked 3.6.1.3.15 -----------

Drywell Pressure 3.6.1.4 3.6.1.4 Verify drywell pressure is within limit 3.6.1.4.1 3.6.1.4.1 Drywell Average Air Temperature 3.6.1.5 3.6.1.5 Verify drywell average air temperature is within limit 3.6.1.5.1 3.6.1.5.1 LLS Valves [QCNPS - Low Set Relief Valves] 3.6.1.6 3.6.1.6 Verify each LLS valve opens when manually actuated 3.6.1.6.1 3.6.1.6.1 Verify LLS system actuates on initiation signal 3.6.1.6.2 3.6.1.6.2 Reactor Building - Suppression Chamber Vacuum Breakers 3.6.1.7 3.6.1.7 Verify each vacuum breaker is closed 3.6.1.7.1 3.6.1.7.1 Perform functional test on each vacuum breaker 3.6.1.7.2 3.6.1.7.2 Verify opening setpoint for each vacuum breaker 3.6.1.7.3 3.6.1.7.3 Suppression Chamber - Drywell Vacuum Breakers 3.6.1.8 3.6.1.8 Verify each vacuum breaker is closed 3.6.1.8.1 3.6.1.8.1 Perform functional test on each vacuum breaker 3.6.1.8.2 3.6.1.8.2 Verify opening setpoint for each vacuum breaker 3.6.1.8.3 3.6.1.8.3 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 3.6.2.1 Verify suppression pool average temperature within limits 3.6.2.1.1 3.6.2.1.1 Suppression Pool Water Level 3.6.2.2 3.6.2.2 Verify suppression pool water level within limits 3.6.2.2.1 3.6.2.2.1 RHR Suppression Pool Cooling 3.6.2.3 3.6.2.3 Verify each valve in flow path is in correct position 3.6.2.3.1 3.6.2.3.1 Verify each RHR pump develops flow rate 3.6.2.3.2 3.6.2.3.2**

RHR Suppression Pool Spray 3.6.2.4 3.6.2.4 Verify each valve in flow path is in correct position 3.6.2.4.1 3.6.2.4.1 Verify RHR pump develops flow rate 3.6.2.4.2 ------------

Page 6 of 10

ATTACHMENT 5 TSTF-425 (NUREG-1433) vs. QCNPS Cross-Reference Technical Specification Section Title/Surveillance Description* TSTF-425 QCNPS Verify spray nozzle unobstructed --------- 3.6.2.4.2 Drywell - Suppression Chamber Differential Pressure 3.6.2.5 3.6.2.5 Verify differential pressure is within limit 3.6.2.5.1 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 3.6.3.1 Verify PC oxygen concentration is within limits 3.6.3.2.1 3.6.3.1.1 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 3.6.4.1 Verify SC vacuum 3.6.4.1.1 3.6.4.1.1 Verify all SC equipment hatches closed and sealed 3.6.4.1.2 3.6.4.1.4 Verify one SC access door in each opening is closed 3.6.4.1.3 3.6.4.1.2 Verify SC drawn down using one SGTS 3.6.4.1.4 ---------

Verify SC can be maintained using one SGTS 3.6.4.1.5 3.6.4.1.3 Secondary Containment Isolation Valves 3.6.4.2 3.6.4.2 Verify each SC isolation manual valve is closed 3.6.4.2.1 3.6.4.2.1 Verify isolation time of each SCIV 3.6.4.2.2 3.6.4.2.2 Verify each automatic SCIV actuates to isolation position 3.6.4.2.3 3.6.4.2.3 Standby Gas Treatment (SGT) System 3.6.4.3 3.6.4.3 Operate each SGT subsystem with heaters operating 3.6.4.3.1 3.6.4.3.1 Verify each SGT subsystem actuates on initiation signal 3.6.4.3.3 3.6.4.3.3 Verify each SGT filter cooler bypass damper can be opened 3.6.4.3.4 -----------

Residual Heat Removal Service Water (RHRSW) System 3.7.1 3.7.1 Verify each RHRSW valve in flow path in correct position 3.7.1.1 3.7.1.1 Plant Service Water (PSW) System and Ultimate Heat Sink (UHS) 3.7.2 3.7.2

[Ulimate Heat Sink (UHS)

Verify water level in cooling tower basin 3.7.2.1 ---------

Verify water level in pump well of pump structure [QCNPS - intake 3.7.2.2 3.7.3.1 bay level]

Verify average water temperature of heat sink [QCNPS - UHS] 3.7.2.3 3.7.3.2 Operate each cooling tower fan 3.7.2.4 ---------

Verify each PSW valve in flow path is in correct position 3.7.2.5 ---------

Verify PSW actuates on initiation signal 3.7.2.6 ---------

Diesel Generator (DG) Standby Service Water (SSW) [Diesel 3.7.3 3.7.2 Generator Cooling Water (DGCW)] System Verify each valve in flow path is in correct position 3.7.3.1 3.7.2.1 Verify pump starts automatically 3.7.3.2 3.7.2.2 MCREC [QCNPS - CREV] System 3.7.4 3.7.4 Operate each MCREC subsystem [QCNPS - Operate CREV 3.7.4.1 3.7.4.1 system]

Verify each subsystem actuates on initiation signal [QCNPS - Verify 3.7.4.3 3.7.4.3 isolation dampers close]

Verify each subsystem can maintain positive pressure 3.7.4.4 ---------

Page 7 of 10

ATTACHMENT 5 TSTF-425 (NUREG-1433) vs. QCNPS Cross-Reference Technical Specification Section Title/Surveillance Description* TSTF-425 QCNPS Control Room [QCNPS - Emergency Ventilation] Air Conditioning 3.7.5 3.7.5 System Verify each subsystem has capability to remove heat load [QCNPS - 3.7.5.1 3.7.5.1 Verify Control Room Emergency AC System has capability to remove heat load]

Main Condenser Offgas 3.7.6 3.7.6 Verify gross gamma activity rate of the noble gases 3.7.6.1 3.7.6.1 Main Turbine Bypass System 3.7.7 3.7.7 Verify one complete cycle of each main turbine bypass valve 3.7.7.1 3.7.7.1 Perform system functional test 3.7.7.2 3.7.7.2 Verify Turbine Bypass System Response Time within limits 3.7.7.3 3.7.7.3 Spent Fuel Storage Pool Water Level 3.7.8 3.7.8 Verify spent fuel storage pool water level 3.7.8.1 3.7.8.1 Safe Shutdown Makeup Pump (SSMP) System ------ 3.7.9 Verify system valves in correct position --------- 3.7.9.1 Verify system pump flow rate --------- 3.7.9.2 AC Sources - Operating 3.8.1 3.8.1 Verify correct breaker alignment 3.8.1.1 3.8.1.1 Verify each DG starts from standby conditions/steady state 3.8.1.2 3.8.1.2 Verify each DG is synchronized and loaded 3.8.1.3 3.8.1.3 Verify each day tank level 3.8.1.4 3.8.1.4 Check for and remove accumulated water from day tank 3.8.1.5 3.8.1.5 Verify fuel oil transfer system operates 3.8.1.6 3.8.1.6 Verify each DG starts from standby conditions/quick start 3.8.1.7 3.8.1.8 Verify transfer of power from offsite circuit to alternate circuit 3.8.1.8 3.8.1.9 Verify DG rejects load greater than single largest load 3.8.1.9 3.8.1.10 Verify DG maintains load following load reject 3.8.1.10 3.8.1.11 Verify on loss of offsite power signal 3.8.1.11 3.8.1.12 Verify DG starts on ECCS initiation signal 3.8.1.12 3.8.1.13 Verify DG automatic trips bypassed on ECCS initiation signal 3.8.1.13 3.8.1.14 Verify each DG operates for > 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 3.8.1.14 3.8.1.15 Verify each DG starts from standby conditions/quick restart 3.8.1.15 3.8.1.16 Verify each DG synchronizes with offsite power 3.8.1.16 3.8.1.17 Verify ECCS initiation signal overrides test mode 3.8.1.17 ---------

Verify interval between each timed load block 3.8.1.18 3.8.1.18 Verify on LOOP in conjunction with ECCS initiation signal 3.8.1.19 3.8.1.19 Verify simultaneous DG starts 3.8.1.20 3.8.1.20 Diesel Fuel Oil, Lube Oil, and Starting Air 3.8.3 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 3.8.3.2 Check/remove accumulated water from fuel oil storage tank 3.8.3.5 3.8.1.7 DC Sources - Operating 3.8.4 3.8.4 Verify battery terminal voltage 3.8.4.1 3.8.4.1 Verify no visible corrosion --------- 3.8.4.2 Verify no physical damage or abnormal deterioration --------- 3.8.4.3 Remove visible corrosion --------- 3.8.4.4 Page 8 of 10

ATTACHMENT 5 TSTF-425 (NUREG-1433) vs. QCNPS Cross-Reference Technical Specification Section Title/Surveillance Description* TSTF-425 QCNPS Verify connection resistance --------- 3.8.4.5 Verify each battery charger supplies amperage 3.8.4.2 3.8.4.6 Verify battery capacity is adequate to maintain emergency loads 3.8.4.3 3.8.4.7 Battery Parameters 3.8.6 3.8.6 Verify battery float current 3.8.6.1 ---------

Verify battery pilot cell voltage 3.8.6.2 3.8.6.1 Verify battery connected cell electrolyte level 3.8.6.3 3.8.6.2 Verify battery pilot cell temperature 3.8.6.4 ---------

Verify battery cell parameters meet Category A --------- 3.8.6.1 Verify battery cell parameters meet Category B ---------- 3.8.6.2 Verify battery connected cell voltage 3.8.6.5 3.8.6.2 Verify electrolyte temperature of representative cells --------- 3.8.6.3 Verify battery capacity during performance discharge test 3.8.6.6 3.8.4.8 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 3.8.7 Verify correct breaker alignment/power to distribution subsystems 3.8.9.1 3.8.7.1 Distribution System - Shutdown 3.8.10 3.8.8 Verify correct breaker alignment/power to distribution subsystems 3.8.10.1 3.8.8.1 Refueling Equipment Interlocks 3.9.1 3.9.1 Channel Functional Test of refueling equip interlock inputs 3.9.1.1 3.9.1.1 Refuel Position One-Rod-Out Interlock 3.9.2 3.9.2 Verify reactor mode switch locked in refuel position 3.9.2.1 3.9.2.1 Perform Channel Functional Test 3.9.2.2 3.9.2.2 Control Rod Position 3.9.3 3.9.3 Verify all control rods fully inserted 3.9.3.1 3.9.3.1 Control Rod Operability - Refuel 3.9.5 3.9.5 Insert each withdrawn control rod one notch 3.9.5.1 3.9.5.1 Verify each withdrawn control rod scram accumulator press 3.9.5.2 3.9.5.2 Reactor Pressure Vessel (RPV) Water Level - Irradiated Fuel 3.9.6 3.9.6 Verify RPV water level 3.9.6.1 3.9.6.1 Reactor Pressure Vessel (RPV) Water Level - New Fuel 3.9.7 3.9.7 Verify RPV water level 3.9.7.1 3.9.7.1 RHR - High Water Level 3.9.8 3.9.8 Verify one RHR shutdown cooling subsystem operating 3.9.8.1 ----------

Monitor reactor coolant temperature --------- 3.9.8.1 Verify RHR shutdown cooling subsystem valve positions ---------- 3.9.8.2 RHR - Low Water Level 3.9.9 3.9.9 Verify one RHR shutdown cooling subsystem operating 3.9.9.1 ---------

Monitor reactor coolant temperature --------- 3.9.9.1 Verify RHR shutdown cooling subsystem valve positions ---------- 3.9.9.2 Reactor Mode Switch Interlock Testing 3.10.2 3.10.1 Verify all control rods fully inserted in core cells 3.10.2.1 3.10.1.1 Verify no core alterations in progress 3.10.2.2 3.10.1.2 Page 9 of 10

ATTACHMENT 5 TSTF-425 (NUREG-1433) vs. QCNPS Cross-Reference Technical Specification Section Title/Surveillance Description* TSTF-425 QCNPS Single Control Rod Withdrawal - Hot Shutdown 3.10.3 3.10.2 Verify all control rods in five-by-five array are disarmed 3.10.3.2 3.10.2.2 Verify all control rods other than withdrawn rod are fully inserted 3.10.3.3 3.10.2.3 Single Control Rod Withdrawal - Cold Shutdown 3.10.4 3.10.3 Verify all control rods in five-by-five array are disarmed 3.10.4.2 3.10.3.2 Verify all control rods other than withdrawn rod are fully inserted 3.10.4.3 3.10.3.3 Verify a control rod withdrawal block is inserted 3.10.4.4 3.10.3.4 Single Control Rod Drive (CRD) Removal - Refuel 3.10.5 3.10.4 Verify all control rods other than withdrawn rod are fully inserted 3.10.5.1 3.10.4.1 Verify all control rods in five-by-five array are disarmed 3.10.5.2 3.10.4.2 Verify a control rod withdrawal block is inserted 3.10.5.3 3.10.4.3 Verify no core alterations in progress 3.10.5.5 3.10.4.5 Multiple CRD Removal-Refuel 3.10.6 3.10.5 Verify four fuel assemblies removed from core cells 3.10.6.1 3.10.5.1 Verify all other rods in core cells inserted 3.10.6.2 3.10.5.2 Verify fuel assemblies being loaded comply with reload sequence 3.10.6.3 3.10.5.3 Shutdown Margin Test - Refueling 3.10.8 3.10.7 Verify no other core alterations in progress 3.10.8.4 3.10.7.4 Verify CRD charging water header pressure 3.10.8.6 3.10.7.6 Recirculation Loops - Testing 3.10.9 --------

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

Programs (Surveillance Frequency Control Program) 5.5.15 5.5.14

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

- This QCNPS Surveillance Frequency is provided in the QCNPS Inservice Testing (IST)

Program. This QCNPS Surveillance Frequency is not proposed for inclusion in the Surveillance Frequency Control Program.

Page 10 of 10

ATTACHMENT 6 Proposed No Significant Hazards Consideration Description of Amendment Request: The proposed amendment would modify the Quad Cities Nuclear Power Station (QCNPS), Units 1 and 2, 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." Additionally, the change would add a new program, the "Surveillance Frequency Control Program" (SFCP), to TS Section 5, "Administrative Controls."

The changes are consistent with NRC-approved TSTF Standard Technical Specifications (STS) change TSTF-425, Revision 3, (ADAMS Accession No. ML090850642). The Federal Register notice published on July 6, 2009 (74 FR 31996) announced the availability of this TS improvement as part of the Consolidated Line Item Improvement Process (CLIIP). The changes are applicable to licensees using probabilistic risk guidelines contained in NRC-approved Nuclear Energy Institute (NEI) 04-10, "Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies, Revision 1 (ADAMS Accession No.

071360456).

Basis for proposed no significant hazards consideration: As required by 10 CFR 50.91(a), the EGC 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 (SRs) to licensee control under a new SFCP. 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 TS for which the surveillance frequencies are relocated are still required to be operable, meet the acceptance criteria for the SRs, 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 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.

Page 1 of 2

ATTACHMENT 6 Proposed No Significant Hazards Consideration 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 the TS), because 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, EGC will utilize the guidance contained in NRC-approved NEI 04-10, in accordance with the TS SFCP. NEI 04-10, Revision 1, methodology provides reasonable acceptance guidelines and methods for evaluating the risk increase of proposed changes to surveillance frequencies consistent with Regulatory Guide 1.177.

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

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

Page 2 of 2

v t e Letter Sequence Request
TAC:ME3374, Relocate Surveillance Frequencies to Licensee Control - RITSTF Initiative 5B (Approved, Closed) TAC:ME3376, Relocate Surveillance Frequencies to Licensee Control - RITSTF Initiative 5B (Open)
Initiation Request, Request, Request, Request Acceptance... Administration Questions 14 May 2010 21 July 2010 Answers Results Approval Other:
MONTHYEAR2010-06-22 [Table View]

RS-10-032, 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)

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3.0 REGULATORY ANALYSIS

4.0 ENVIRONMENTAL CONSIDERATION

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RS-10-032, 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)

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Subject:

1.0 DESCRIPTION

3.0 REGULATORY ANALYSIS

4.0 ENVIRONMENTAL CONSIDERATION

5.0 REFERENCES

1.0 DESCRIPTION

3.0 REGULATORY ANALYSIS

4.0 ENVIRONMENTAL CONSIDERATION

5.0 REFERENCES

SUMMARY

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