Text

Proposed License Amendment Request Regarding Risk-Informed Justification for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program (Adoption of TSTF-425, Revision 3)
	ML100900163
Person / Time
Site:	North Anna
Issue date:	03/30/2010
From:	Price J; Virginia Electric & Power Co (VEPCO)
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
Shared Package
ML100900162	List: ML100900163; ML100900167;
References
	10-122
	Download: ML100900163 (133)
	v • d • e

10 CFR 50.90 VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 March 30, 2010 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D.C. 20555 Serial No.10-122 NL&OS/ETS RO Docket Nos. 50-338/339 License Nos. NPF-4/7 VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

NORTH ANNA POWER STATION UNITS 1 AND 2 PROPOSED LICENSE AMENDMENT REQUEST REGARDING RISK-INFORMED JUSTIFICATION FOR THE RELOCATION OF SPECIFIC SURVEILLANCE FREQUENCY REQUIREMENTS TO A LICENSEE CONTROLLED PROGRAM (ADOPTION OF TSTF-425, REVISION 3)

Dominion requests amendments, in the form of changes to the Technical Specifications (TS) to Facility Operating License Numbers NPF-4 and NPF-7, for North Anna Power Station Units 1 and 2, respectively.

The proposed amendments would modify North Anna TS by relocating specific surveillance frequencies to a licensee-controlled program with the implementation of Nuclear Energy Institute (NEI) 04-10, "Risk;-

Informed Technical Specifications Initiative 5b, Risk-Informed Method for Controlof'~'

Surveillance Frequencies."

The changes are consistent with NRC-approved Industry Technical Specifications Task Force (TSTF) Standard Technical Specifications (STS) change TSTF*A25, Revision 3, (ADAMS Accession No. ML090850642). The Federal Register notice published on July 6, 2009 (74 FR31996), announced the availability of this TS improvement.

Attachment 1

provides a description of the proposed change, the requested confirmation of applicability, and plant-specific verifications. Attachment 2 provides documentation of the Probabilistic Risk Assessment (PRA) technical adequacy. provides the marked-up North Anna Units 1 and 2 TS pages to show the proposed changes. Attachment 4 provides the marked-up North Anna Units 1. and 2IS Bases changes for information. provides a TSTF-425 (NUREG-1431) versus North Anna TS Cross-Reference. provides the proposed No Significant Hazards Consideration.

These proposed changes have been reviewed and approved by the Facility Safety Review Board.

Dominion requests approval of the proposed license amendments by April 1, 2011, with the amendments being implemented within 120 days.

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

,2010.

~"t~

Notary Public Serial No.10-122 Docket Nos. 50-338/339 LAR - Relocate Surveillance Frequencies from TS Page 2 of 3 If you have any questions or require additional information, please contact Mr. Thomas Shaub at (804) 273-2763.

Very truly yours, rice sident - Nuclear Engineering Attachments:

1. Description and Assessment

2. Documentation of PRA Technical Adequacy

3. Marked-up Technical Specification Page Changes - Units 1 and 2

4. Marked-up Technical Specification Bases Page Changes - Units 1 and 2

5. TSTF-425 (NUREG-1431) vs. North Anna Cross-Reference

6. Proposed No Significant Hazards Consideration Commitments made in this letter: None COMMONWEALTH OF VIRGINIA

)

COUNTY OF HENRICO

)

The foregoing document was acknowledged before me, in and for the County and Commonwealth aforesaid, today by J. Alan Price, who is Vice President - Nuclear Engineering, of Virginia Electric and Power Company.

He has affirmed before me that he is duly authorized to execute and file the foregoing document in behalf of that Company, and that the statements in the document are true to the best of his knowledge and belief.

Acknowledged before me this.ttJ1J'day of..,;!11hz;'

My Commission Expires: ~131 @IO I

VICKIL. HULL Notary Public l

Commonwealth of Virginia 140542 My CommlNlon Explr** MaV 31, 2010

cc:

u.s. Nuclear Regulatory Commission Region II Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW Suite 23T85 Atlanta, Georgia 30303 Mr. J. E. Reasor, Jr.

Old Dominion Electric Cooperative Innsbrook Corporate Center 4201 Dominion Blvd.

Suite 300 Glen Allen, Virginia 23060 State Health Commissioner Virginia Department of Health James Madison Building - 7th floor 109 Governor Street Suite 730 Richmond, Virginia 23219 NRC Senior Resident Inspector North Anna Power Station Ms. K. R. Cotton NRC Project Manager U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 08 G9A 11555 Rockville Pike Rockville, Maryland 20852 Dr. V. Sreenivas NRC Project Manager U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 08 G9A 11555 Rockville Pike Rockville, Maryland 20852 Serial No.10-122 Docket Nos. 50-338/339 LAR - Relocate Surveillance Frequencies from TS Page 3 of 3

Serial No.1 0-122 Docket Nos. 50-338/339 LAR - Relocate Surveillance Frequencies from TS ATTACHMENT 1 DESCRIPTION AND ASSESSMENT VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

NORTH ANNA POWER STATION UNITS 1 AND 2

Serial No.10-122 Docket Nos. 50-338/50-339 Page 1 of 5 DESCRIPTION AND ASSESSMENT OF PROPOSED CHANGES

1.0 DESCRIPTION

The proposed amendment would modify North Anna Technical Specifications 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, to TS Section 5, Administrative Controls.

The changes are consistent with NRC-approved Industry/TSTF Standard Technical Specifications (STS) change TSTF-425, Revision 3,

(ADAMS Accession No.

ML090850642). The Federal Register notice published on July 6,2009 (74 FR 31996),

announced the availability of this TS improvement.

2.0 ASSESSMENT

2.1 Applicability of Published Safety Evaluation Dominion has reviewed the safety evaluation dated July 6,2009. This review included a review of the NRC staff's evaluation, TSTF-425, Revision 3, and the requirements specified in NEI 04-10, Rev. 1, (ADAMS Accession No. ML071360456). includes Dominion documentation with regard to PRA technical adequacy consistent with the requirements of Regulatory Guide 1.200, Revision 1 (ADAMS Accession No. ML070240001), Section 4.2, and describes any PRA models without NRC-endorsed standards, including documentation of the quality characteristics of those models in accordance with Regulatory Guide 1. 200.

Dominion has concluded that the justifications presented in the TSTF proposal and the safety evaluation prepared by the NRC staff are applicable to North Anna Power Station Units 1 and 2 and justify this amendment to incorporate the changes to the North Anna Power Station Units 1 and 2 TS.

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

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

Providing only mark-ups of the proposed TS changes satisfies the requirements of 10 CFR 50.90 in that the mark-ups fully describe the changes desired.

This represents an administrative deviation from the NRC staff's model

Serial NO.1 0-122 Docket Nos. 50-338/50-339 Page 2 of 5 application dated July 6, 2009 (74 FR 31996) with no impact on the NRC staff's model safety evaluation published in the same Federal Register Notice. As a result of this deviation, the contents and numbering of the attachments for this amendment request differ from the attachments specified in the NRC staff's model application.

Mark-ups of the proposed TS changes are provided in Attachments 3. Additionally, mark-ups of the proposed changes to TS Bases pages are provided in Attachment

4. (NOTE: Some TS Bases pages provided may not contain any mark-ups. These pages are provided for completeness and for information purposes only.)

2. The definition of STAGGERED TEST BASIS is being retained in North Anna TS Definition Section 1.1 since this terminology is mentioned in Administrative TS Section 5.5.16, "Control Room Habitability," which is not the subject of this amendment request and is not proposed to be changed.

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

3. The insert provided in TSTF-425 to replace text describing the basis for each frequency relocated to the Surveillance Frequency Control Program 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 NAPS basis for frequencies which do not, in all cases, base Frequency on operating experience, equipment reliability, and plant risk.

4. NAPS TS Surveillance Requirement (SR) 3.8.4.8, Note 2, states: "The performance discharge test in SR 3.8.4.9 may be performed in lieu of the service test in SR 3.8.4.8 once every 60 months." The statement "once every 60 months" in Note 2 is a reference to the Frequency associated with TS SR 3.8.4.9. Since TS SR 3.8.4.9 itself is already referenced in Note 2, the reference to the Frequency associated with TS SR 3.8.4.9 is redundant, and can therefore be deleted. This proposed change is consistent with NUREG-1431, since Note 1 of TS SR 3.8.4.3 (which corresponds to NAPS TS SR 3.8.4.8) only references TS SR 3.8.6.6 (which corresponds to NAPS TS SR 3.8.4.9) itself, and does not also reference the Frequency associated with TS SR 3.8.6.6 in the Note.

In accordance with TSTF-425, and as indicated in the proposed NAPS TS markups in this amendment request, the 60-month Frequency for TS SR 3.8.4.8 is proposed to be relocated to the Surveillance Frequency Control Program (SFCP). Deleting the statement "once every 60 months" from Note 2 in TS SR 3.8.4.7 would allow future changes to the 60-month Frequency for TS SR 3.8.4.8 to be evaluated under the SFCP using the methodology contained in NE104-1 0, Revision 1, "Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies,"

(ADAMS Accession No.

ML071360456). Deleting the statement from Note 2 is consistent with TSTF-425 as approved by NRC letter dated September 19, 2007 (ADAMS Accession No. ML072570267).

Serial No.10-122 Docket Nos. 50-338/50-339 Page 3 of 5

5. Attachment 5 provides a cross-reference between the NUREG-1431 Surveillances included in TSTF-425 versus the NAPS Surveillances included in this amendment request. Attachment 5 includes a summary description of the referenced TSTF-425 (NUREG-1431)/NAPS TS Surveillances which is provided for information purposes only and is not intended to be a verbatim description of the TS Surveillances. This cross reference highlights the following:

a. NUREG-1431 Surveillances included in TSTF-425 and corresponding NAPS Surveillances with identical Surveillance numbers,

b. NUREG-1431 Surveillances included in TSTF-425 and corresponding NAPS Surveillances with plant specific Surveillances numbers,

c. NUREG-1431 Surveillances included in TSTF-425 that are not contained in the NAPS TS, and

d. NAPS plant-specific Surveillances that are not contained in NUREG-1431, and therefore, are not included in the TSTF-425 mark-ups.

NAPS Surveillances that have Surveillance numbers identical to the corresponding NUREG-1431 Surveillances are not deviations from TSTF-425. NAPS plant-specific Surveillances with Surveillance numbers that differ from the corresponding NUREG-1431 Surveillances are administrative deviations from TSTF-425 with no impact on the NRC staff's model safety evaluation dated July 6, 2009 (74 FR 31996).

For NUREG-1431 Surveillances that are not contained in the NAPS TS, the corresponding NUREG-1431 mark-ups included in TSTF-425 for these Surveillances are not applicable to NAPS. This is an administrative deviation from TSTF-425 with no impact on the NRC staff's model safety evaluation dated July 6, 2009 (74 FR 31996).

For NAPS plant-specific Surveillances that are not contained in NUREG-1431, and therefore, are not included in the NUREG-1431 mark-ups provided in TSTF-425, Dominion has determined that since the plant-specific Surveillances involve fixed periodic Frequencies, the relocation of the Frequencies for these NAPS plant-specific Surveillances is consistent with TSTF-425, Revision 3, and with the NRC staff's model safety evaluation dated July 6, 2009 (74 FR 31996), including the scope exclusions identified in Section 1.0, "Introduction," of the model safety evaluation.

In accordance with TSTF-425, changes to the Frequencies for these Surveillances would be controlled under the Surveillance Frequency Control Program (SFCP).

The SFCP provides the necessary administrative controls to require that Surveillances related to testing, calibration and inspection are conducted at a frequency to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met. Changes to Frequencies in the SFCP would be evaluated using the methodology and probabilistic risk guidelines contained in NEI 04-10, Revision 1, "Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies," (ADAMS Accession No.

Serial No.10-122 Docket Nos. 50-338/50-339 Page 4 of 5 ML071360456), as approved by NRC letter dated September 19, 2007 (ADAMS Accession No. ML072570267).

The NEI 04-10, Revision 1 methodology includes qualitative considerations, risk analyses, sensitivity studies and bounding analyses, as necessary, and recommended monitoring of the performance of systems, components, and structures (SSCs) for which Frequencies are changed to assure that reduced testing does not adversely impact the SSCs. In addition, the NEI 04-10, Revision 1 methodology satisfies the five key safety principles specified in Regulatory Guide 1.177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications," dated August 1998, relative to changes in Surveillance Frequencies.

3.0 REGULATORY ANALYSIS

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

Dominion has concluded that the proposed NSHC presented in the Federal Register notice is applicable to North Anna Units 1 and 2, and is provided as Attachment 6 to this amendment request, which satisfies the requirements of 10 CFR 50.91 (a).

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

Dominion has concluded that the relationship of the proposed changes to the applicable regulatory requirements presented in the Federal Register notice is applicable to North Anna 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 Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

4.0 ENVIRONMENTAL CONSIDERATION

Dominion has reviewed the environmental consideration included in the NRC staff's model safety evaluation published in the Federal Register on July 6, 2009 (74 FR 31996). Dominion has concluded that the staff's findings presented therein are applicable to North Anna Units 1 and 2, and the determination is hereby incorporated by reference for this application.

Serial No.10-122 Docket Nos. 50-338/50-339 Page 5 of 5

5.0 REFERENCES

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

RITSTF Initiative 5b,"

March 18, 2009 (ADAMS Accession Number:

ML090850642).

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

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

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

January 2007 (ADAMS Accession Number: ML070240001).

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

Technical Specifications,"

dated August 1998 (ADAMS Accession No. ML003740176).

Serial No.1 0-122 Docket Nos. 50-338/339 LAR - Relocate Surveillance Frequencies from TS ATTACHMENT 2 DOCUMENTATION OF PRA TECHNICAL ADEQUACY VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

NORTH ANNA POWER STATION UNITS 1 AND 2

Serial No.10-122 Docket Nos. 50-338/50-339 Page 1 of 15 PRA Technical Adequacy PRA Quality Overview The implementation of the Surveillance Frequency Control Program (also referred to as Technical Specifications Initiative 5b) at North Anna Power Station (NAPS) will follow the guidance provided in NEI 04-10, Revision 1 [Ref. 1] in evaluating proposed surveillance test interval (STI; also referred to as "surveillance frequency") changes.

The following steps of the risk-informed STI revision process are common to all proposed STls changes 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.

Only after receiving formal NRC approval to change the commitment would a STI revision proceed.

A qualitative analysis is performed for each STI revision that involves several considerations as explained in NEI 04-10, Revision 1.

Each STI revision is reviewed by an Expert Panel, referred to as the Integrated Oecisionmaking Panel (lOP), 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 lOP approves the STI revision, the change is documented and implemented, and available for future audits by the NRC. If the lOP does not approve the STI revision, the STI value is left unchanged.

Performance monitoring is conducted as recommended by the lOP. 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 lOP 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 lOP returns the STI back to the previously acceptable STI.

In addition to the above steps, the Probabilistic Risk Assessment (PRA) is used when possible to quantify the effect of a proposed individual STI revision compared to acceptance criteria in NEI 04-10, Revision 1. Also, the cumulative impact of all risk-informed STI revisions on all PRA evaluations (i.e., internal

Serial No.10-122 Docket Nos. 50-338/50-339 Page 2 of 15 events, external events and shutdown) is also compared to the risk acceptance criteria as delineated in NEI 04-10, Revision 1.

For those cases where the STI cannot be modeled in the plant PRA (or where a particular PRA model does not exist for a given hazard group), a qualitative or bounding analysis is performed to provide justification for the acceptability of the proposed test interval change. The NEI 04-10, Revision 1 methodology endorses the guidance provided in Regulatory Guide (RG) 1.200, Revision 1 [Ref. 2], "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities." The guidance in RG 1.200 indicates that the following steps should be followed when performing PRA assessments (NOTE: Because of the broad scope of potential Initiative 5b applications and the fact that the risk assessment details will differ from application to application, each of the issues encompassed in Items 1 through 3 below will be covered with the preparation of each individual PRA assessment made in support of the individual STI interval requests. Item 3 satisfies one of the requirements of Section 4.2 of RG 1.200. The remaining requirements of Section 4.2 are addressed by Item 4 below.):

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

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

A definition of the acceptance criteria used for the application.

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

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

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

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

4. Demonstrate the Technical Adequacy of the PRA.

Identify plant changes (design or operational practices) that have been incorporated at the site, but are not yet in the PRA model and justify why the change does not impact the PRA results used to support the application.

Document peer review findings and observations that are applicable to the parts of the PRA required for the application, and for those that have not yet been addressed justify why the significant contributors would not be impacted.

Document that the parts of the PRA used in the decision are consistent with applicable standards endorsed by the Regulatory Guide (currently, RG 1.200, Revision 1, includes only internal events PRA standard). Provide justification to show that where specific requirements in the standard are not adequately met, it will not unduly impact the results.

Serial No.10-122 Docket Nos. 50-338/50-339 Page 3 of 15 Identify key assumptions and approximations relevant to the results used in the decision-making process.

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

Technical Adequacy of the PRA Model The NAPS PRA model of record, N009A, and associated documentation has been maintained as a living program, and the PRA is updated approximately every 3 years to reflect the as-built as-operated plant.

The N009A PRA model is highly detailed, including a wide variety of initiating events, modeled systems, operator actions, and common cause events. The PRA model quantification process used for the NAPS PRA is based on the event tree / fault tree methodology, which is a well-known methodology in the industry.

Dominion employs a structured approach to establishing and maintaining the technical adequacy and plant fidelity of the PRA models for all operating Dominion 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 NAPS PRA.

PRA Maintenance and Update The North Anna Power Station (NAPS) PRA model and documentation has been maintained as. a living program, and the PRA is routinely updated approximately every 3 years to reflect the current plant configuration and to reflect the accumulation of additional plant operating history and component failure data.

There are several procedures and GARDs (Guidance and Reference Documentation) that govern Dominion's PRA program.

Procedure NF-AA-PRA-101 controls the maintenance and use of the PRA documentation and the associated NF-AA-PRA Procedures and GARDs. These documents define the process to delineate the types of calculations to be performed, the computer codes and models used, and the process (or technique) by which each calculation is performed.

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

Perform probabilistic risk assessments for the Dominion Nuclear Fleet, including Kewaunee, Millstone, North Anna and Surry Power Stations Create and maintain products to support licensing and plant operation concerns for the Dominion Nuclear Fleet Provide PRA model configuration control Create and maintain configuration risk evaluation tools for the Dominion Nuclear Fleet

Serial No.10-122 Docket Nos. 50-338/50-339 Page 4 of 15 The purpose of the NF-AA-PRA GARDs and Procedures is to provide information and guidelines for performing probabilistic risk assessments. Nevertheless, non-routine risk assessments are often

unique, requiring departure from these guidelines and information in order to correctly perform and meet the risk assessment objectives.

A procedurally controlled process is used to maintain configuration control of the NAPS PRA

models, data, and software.

In addition to model

control, administrative mechanisms are in place to assure that plant modifications, procedure changes, calculations, operator training, system operation changes, and industry operating experiences (DEs) are appropriately

screened, dispositioned, and scheduled for incorporation into the model. These processes help assure that the NAPS PRA reflects the as-built, as-operated plant within the limitations of the PRA methodology.

This process involves a periodic review and update cycle to model any changes in the plant design or operation. Plant hardware and procedure changes are reviewed on an approximate quarterly or more frequent basis to determine if they impact the PRA and if a PRA modeling and/or documentation change is warranted. These reviews are documented, and if any PRA changes are warranted, they are added to the PRA Configuration Control (PRACC) database for PRA implementation tracking.

As part of the PRA evaluation for each STI change request, a review of open items in the PRACC database 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 Expert Panel. If a nontrivial impact is expected, then this may include the performance of additional sensitivity studies or PRA model changes to confirm the impact on the risk analysis.

The NAPS PRACC database was reviewed to identify any open (Le., not yet officially resolved and incorporated into the PRA) PRACC items. The open PRACC items contain identified PRA changes to address plant modifications (as discussed above) as well as changes to correct errors or to enhance the model.

The Level 1 and Level 2 NAPS PRA analyses were originally developed and submitted to the NRC in 1992 as the Individual Plant Examination (IPE) Submittal.

The NAPS PRA has been updated many times, since the original IPE. A summary of the NAPS PRA history is as follows:

1992 DriginallPE 1994 Submitted IPEEE Seismic only 1997 Submitted IPEEE Fire and other External Events 1997 Data update; update to address issues needed to support the Maintenance Rule program

Serial No.10-122 Docket Nos. 50-338/50-339 Page 5 of 15 2001 Model Update to Support WOG PRA Peer Review 2000 Addressed several F&Os identified during PRA Peer Review 2005 Data update; update to address requirements for MSPI 2007 Data update; addressed ASME PRA Standard SRs that were not met; extensive changes throughout the model as the model was converted to Cafta, Comprehensive Critical Reviews The NAPS PRA model has benefited from the following comprehensive technical PRA Peer Reviews:

NEI PRA Peer Review The NAPS internal events PRA received a formal industry PRA Peer Review in 2001

[Ref. 5].

The purpose of the PRA Peer Review process is to provide a method for establishing the technical quality of a PRA for the spectrum of potential risk-informed plant licensing applications for which the PRA may be used.

The PRA Peer Review process used a team composed of industry PRA and system analysts, each with significant expertise in both PRA development and PRA applications.

This team provided both an objective review of the PRA technical elements and a subjective assessment, based on their PRA experience, regarding the acceptability of the PRA elements.

The team used a set of checklists as a framework within which to evaluate the scope, comprehensiveness, completeness, and fidelity of the PRA products available.

The NAPS review team used the "Westinghouse Owner's Group (WOG)

Peer Review Process Guidance" as the basis for the review.

The general scope of the implementation of the PRA Peer Review included a review of eleven main technical elements, using checklist tables (to cover the elements and sub-elements),

for an at-power PRA including internal

events, internal flooding, and containment performance, with focus on Large Early Release Frequency (LERF).

The F&Os from the PRA Peer Review were prioritized into four categories (A through D) based upon importance to the completeness of the model. All comments in Categories A and B have been updated with the exception of three category B items, which will be resolved in the next model update. Table 1 (Gap #1) provides the current status three of open Category B F&Os. The comments in Categories C and D (good practices and editorial) are potential enhancements for consideration in future updates of the NAPS PRA model.

NAPS PRA Self-Assessment A self-assessment/independent review of the NAPS PRA against the ASME PRA Standard was performed by Dominion with the support of a contracting company, MARACOR, in late 2007 using guidance provided in NRC Regulatory Guide RG 1.200, Revision 1, "An Approach for Determining the Technical Adequacy of Probabilistic Risk

Serial NO.1 0-122 Docket Nos. 50-338/50-339 Page 6 of 15 Assessment Results from Risk-Informed Activities" [Ref. 6]. This self-assessment was documented and used as a planning guide for the NAPS 2009 model update.

Many of the Supporting Requirements (SRs) identified in the self-assessment as not meeting capability category II have been incorporated into the NAPS 2009 model of record (N009A). The improvements made to the model involved documenting sources of uncertainty/assumptions, systematic process for establishing CCF groups, updating several thermal hydraulic (e.g., MAAP computer code) runs and improving success criteria documentation.

In the N009A model update, nearly all of the remaining SRs were addressed by further upgrades to the model documentation as well as improvements to the model. Of the 321 SRs, the NAPS PRA does not meet 22 category II SRs. Ten of the twenty-two "not met" requirements pertain to various documentation issues. There are twelve issues associated with modeling of support system initiating events, recovery actions, consequential loss of RCP seal cooling, cross-tie electrical bus unavailability, inadvertent SI actuation, and PZR PORVs failing to reclose on water relief. Table 1 (Gaps 2 through 17) provides the status of identified gaps.

Serial NO.1 0-122 Docket Nos. 50-338/50-339 Page 7 of 15 Table 1 Status of identified Gaps to NEI 00-02 and Capability Category II of the ASME PRA Standard Title Description NEI Element I Current Status I Comment Importance to Application ASME SR Gap #1 ATWS modeling of AS-9, ATWS Failure Relief Probability is Conservative modeling of the ATWS Failure potentially dominate QU-11, conservatively modeled based on Probabilities will be addressed by sensitivities per NEI sequences and data ST-13 a UET of 27%.

04-10, Revision 1 if applicable to the specific STI traceability evaluation.

Gap #2 For initiating event IE-C8 The current NAPS system-level Support system-level initiating event fault trees will be fault-tree modeling, initiating event fault trees uses a addressed by sensitivities per NEI 04-10, Revision 1 if capture all relevant 365*Capacity Factor multiplier in applicable to the specific STI evaluation.

combinations of events all of the initiating event fault trees, involving the annual which needs to be replaced with frequency of one the new methodology described in component failure EPRI TR-1013490, "Support combined with the System Initiating Events:

unavailability of other Identification and Quantification components Guideline", EPRI, December 2006.

Gap #3 For key safety functions AS-A4 SR is NOT MET until: 1) an HEP is

1) HEP for restoring of ECCS during SBO will be (e.g., power added to the SBO nodes for addressed by sensitivities per NEI 04-10, Revision 1 if restoration) identify restoring the ECCS functions; and applicable to the specific STI evaluation, operator actions to

2) text in section 2.3.3.1 is revised

2) None. This is judged to be a documentation achieve the defined to clarify the need for operator consideration only and does not affect the technical success criteria.

action to restart ECCS functions.

adequacy of the PRA model.

Gap #4 Delineate accident AS-A7 SR is NOT MET until: 1) inclusion

1) Consequential loss of RCP seal cooling for sequence (e.g., Loss of of consequential loss of RCP seal transients will be addressed by sensitivities per NEI 04-RCP seal cooling) for cooling for transients, and 2) 10, Revision 1 if applicable to the specific STI each initiating event documentation enhancement of evaluation.

(e.g., transients).

the U1-RCPSL nodes.

2) None. This is judged to be a documentation consideration only and does not affect the technical adequacy of the PRA model.

Gap #5 Define and model plant AS-B5a Cross-tie unavailability due to Cross-tie electrical bus unavailability due to refueling configurations and outages is accounted for with the outages will be addressed by sensitivities per NEI 04-alignments that reflect exception of electrical buses where 10, Revision 1 if applicable to the specific STI dependencies.

the unavailability during at power evaluation.

operation is essentially 0 versus one or two days during refueling outages.

Serial No.10-122 Docket Nos. 50-338/50-339 Page 8 of 15 Table 1 Status of identified Gaps to NEI 00-02 and Capability Category II of the ASME PRA Standard Title Description NEI Element I Current Status I Comment Importance to Application ASME SR Gap #6 Include a discussion of SC-A6 Some of the success criteria None. This is judged to be a documentation operator actions discussion includes general consideration only and does not affect the technical assumed as part of the operator actions, but the adequacy of the PRA model.

success criteria discussion does not include development, and how procedures and not all event tree those actions are sections contain the discussion consistent with plant procedures and practices Gap #7 Incorporate the effect of SY-A11 The current NAPS PRA does not Inadvertent SI Actuation will be addressed by variable success SY-A13 include inadvertent SI Actuation.

sensitivities per NEI 04-10, Revision 1 if applicable to criteria (i.e., success the specific STI evaluation.

criteria that change as a function of plant status) into the system modeling. Include consideration of all failure modes, consistent with available data and model level of detail Gap #8 Use results of plant SY-A2 The Dominion PRA staff has Not Significant. This is judged to be a documentation walkdowns and plant SY-A4 performed many system consideration only and does not affect the technical personnel interviews SY-B8 walkdowns during the adequacy of the PRA model.

(system engineers and SY-C1 development and maintenance of operators) as a source the models. In addition, Dominion of information for PRA staff works closely with North modeling the as-built, Anna system engineers and as-operated plant.

operators on nearly a daily basis while supporting the various risk informed programs. However, no formal documentation exists at this time to allow closure of these SRs.

It is NOT anticipated that not meeting this requirement will have a sionificant impact on the model.

Serial No.10-122 Docket Nos. 50-338/50-339 Page 9 of 15 Table 1 Status of identified Gaps to NEI 00-02 and Capability Category II of the ASME PRA Standard Title Description NEI Element /

Current Status I Comment Importance to Application ASME SR Gap #9 Identify SSCs that may SY-B15 Currently, the NAPS PRA model PZR PORVs failing to reclose on water relief will be be required to operate does not distinguish between PZR addressed by sensitivities per NEI 04-10, Revision 1 if in conditions beyond PORVs failing to reclose on water applicable to the specific STI evaluation.

their environmental relief and steam qualifications.

Gap #10 Base the time available HR-G4 Time windows for successful Several HEP MAAP runs need to be updated and, to complete actions on completion of actions in some therefore, these will be addressed by sensitivities per appropriate realistic instances may need to be updated NEI 04-10, Revision 1 if applicable to the specific STI generic thermal-(for example, those that are based evaluation. Note not all necessary MAAP runs were hydraulic analyses, or on estimates made for the IPE) updated for N009A.

simulation from similar plants Gap #11 Base the required time HR-G5 No formal documentation currently Not Significant. This is judged to be a documentation to complete actions for exists and this SR will remain NOT consideration only and does not affect the technical significant HFEs on MET. As a footnote the timings adequacy of the PRA model.

action time are not expected to change measurements in either significantly as they are based on walkthroughs or talk-comparisons with similar actions at throughs of the Surry.

procedures or simulator observations.

Gap #12 Check the consistency HR-G6 Document a review of the HFEs Not Significant. This is judged to be a documentation of post-initiator HEPs.

and their final HEPs relative to consideration only and does not affect the technical each other to confirm their adequacy of the PRA model.

reasonableness given the scenario context, plant history, procedures, operational practices, and experience Gap #13 When using expert DA-D2 Documentation needs to be Not Significant. This is judged to be a documentation judgment document the enhanced for the several cases consideration only and does not affect the technical rationale behind the where expert opinion is used. The adequacy of the PRA model choice of parameter expert opinion is reasonable and values.

should not chance,

Serial No.10-122 Docket Nos. 50-338/50-339 Page 10 of 15 Table 1 Status of identified Gaps to NEI 00-02 and Capability Category II of the ASME PRA Standard Title Description NEI Element /

Current Status / Comment Importance to Application ASME SR Gap #14 Identify method-specific QU-B1 Although key assumptions are Not Significant. This is judged to be a documentation limitations and features QU-F5 documented, these do not include consideration only and does not affect the technical that could impact the limitations of the quantification adequacy of the PRA model.

results and method or features that impact applications.

results (aside from references to code limitations, guidance documents and procedures).

Gap #15 Identify key sources of QU-E1 Each PRA element notebook (IE, Not Significant. The PRA documentation has identified model uncertainty.

AS,SC,SY,DA,HR,LE)has potential sources of modeling uncertainty. The identified potential sources of potential sources of uncertainty will be addressed by model uncertainty. A sensitivities per NEI 04-10, Revision 1 if applicable to characterization of those sources the specific STI evaluation.

of uncertainty and evaluation of the generic sources of uncertainty has not yet been completed however.

Gap #16 Provide a detailed QU-F3 Significant contributors (based on Not Significant. This is judged to be a documentation description of F-Vand RAW) have been consideration only and does not affect the technical significant accident identified and evaluated. A detailed adequacy of the PRA model.

sequences or functional description has been provided for failure groups.

the top 5 accident sequences, but not for all significant accident sequences or functional failure qroups.

Gap #17 Perform realistic LE-D4 Secondary side isolation during a The effect of additional relief valve demands will be secondary side SGTR should also consider the addressed by sensitivity studies per NEI 04-10, isolation capability additional number of demands on Revision 1, if applicable to the specific STI evaluation.

analysis for the the relief valves in the progression significant accident to core damage.

progression sequences caused by SG tube release.

Serial No.10-122 Docket Nos. 50-338/50-339 Page 11 of 15 External Events Considerations IPEEE The NEI 04-10, Revision 1 methodology allows for STI change evaluations to be performed in the absence of quantifiable PRA models for all external hazards. For those cases where the STI cannot be modeled in the plant PRA (or where a particular PRA model does not exist for a given hazard group), a qualitative or bounding analysis is performed to provide justification for the acceptability of the proposed test interval change.

External hazards were evaluated in the NAPS Individual Plant Examination for External Events (IPEEE) submittal in response to the NRC IPEEE Program (Generic Letter 88-20 Supplement 4) [Ref. 9]. The IPEEE Program was a one-time review of external hazard risks and was limited in its purpose to the identification of potential plant vulnerabilities and the understanding of associated severe accident risks.

The results of the NAPS "non-seismic external events and fires" IPEEE study are documented in the NAPS IPEEE Main Report [Ref. 3]. The NAPS "seismic" IPEEE study was submitted in 1997 [Ref. 4].

Each of the NAPS external event evaluations were reviewed by the NRC and compared to the requirements of NUREG-1407 [Ref.

11]. The NRC transmitted to Dominion in 2000 their Staff Evaluation Report of the NAPS IPEEE Submittal [Ref. 7].

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

Discussion of External Events Evaluation Seismic PRA Generic Letter (GL) 88-20, Supplement 4, "Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities" was issued by the Nuclear Regulatory Commission (NRC) in June 1991. This letter and NRC NUREG-1407, "Procedural and Submittal Guidance for the Individual Plant Examination of External Events for Severe Accident Vulnerabilities", published June 1991, requested each nuclear plant licensee to perform IPEEE. In a December 1991 letter to the NRC, North Anna identified the planned approach to address IPEEE. For non-seismic external events and fires, the IPEEE effort was completed and a report was submitted to the NRC in June 1994.

For the seismic event, North Anna Power Station was categorized in NUREG-1407 as a focused scope plant. As identified in North Anna's December 1991 letter, the Seismic Margins Method (SMM) developed by Electric Power Research Institute (EPRI) with

Serial No.10-122 Docket Nos. 50-338/50-339 Page 12 of 15 enhancements was selected for North Anna Power Station. A completion schedule for IPEEE - Seismic was initially provided by North Anna Power Station in its September 1992 letter to the NRC which also noted that elements of the effort to resolve IPEEE -

Seismic, notably plant walkdowns, will be integrated with the resolution of Unresolved Safety Issue (USI) A-46 identified in NRC's Supplement 1 to GL 87-02 of May 1992.

In September 1995, the NRC issued Supplement 5 to GL 88-20. This letter gave further guidance on the basis for selection of components that needed capacity evaluation.

Based on GL 88-20, Supplement 5, North Anna submitted a revised approach to NRC in November 1995. This approach, while still retaining the EPRI SMM methodology and treating North Anna as a focused scope plant, identified areas where screening and judgment by experienced and trained engineers would eliminate the need for performing capacity calculations for rugged components, structures, and systems; and require such evaluations only for weaker and critical components. The IPEEE - Seismic program at North Anna Power Station has been performed in accordance with the EPRI SMM methodology for a focused plant and North Anna's stated commitments.

At the onset of the IPEEE - Seismic effort, median centered, In-Structure Response Spectra (ISRS) were developed for a Review Level Earthquake (RLE) for the various North Anna Station buildings. The RLE was based on the NUREGICR-0098 ground response spectrum shape, anchored at horizontal peak ground acceleration (pga) of 0.3g. Success path logic diagrams were developed which formed the basis of identifying a

preferred success path and an alternate success path for safe shutdown.

Components and systems were selected that perform the following four safety functions: Reactor Reactivity Control, Reactor Coolant Pressure Control, Reactor Coolant Inventory Control, and Decay Heat Removal. In addition, components from supporting systems were included. This established a Safe Shutdown Equipment List (SSEL). A relay seismic functionality review was not performed in the IPEEE-Seismic effort, consistent with the NUREG-1407 guidelines, because no low ruggedness relays were found at North Anna Power Station during the resolution of US1 A-46.

The IPEEE-Seismic review consisted of plant walkdowns, analytical reviews to determine high-confidence-of-Iow-probability-of-failure (HCLPF) capacities, and several enhancements (including those for USI A-46) accomplished via design change modifications. Approximately 1800 SSEL items of equipment were walked down by Seismic Review Teams (SRT) consisting of trained and experienced engineers.

Walkdowns of safety significant areas at North Anna Units 1 and 2 were performed to review the potential of seismic induced fire and flood and other potential seismic vulnerabilities related to systems, structures, and components. The vast majority of these walkdowns were performed by in-house SRTs.

Several conditions requiring review were identified as a result of the walkdowns and analyses. Most of these conditions have been resolved via design modifications and additional analytical evaluations. A few issues, primarily related to seismic interactions, remain and are planned to be resolved at a later date. None of the outstanding issues is considered to be a safety concern; however, their resolution could lead to the safety enhancement of the plant.

Serial No.1 0-122 Docket Nos. 50-338/50-339 Page 13 of 15 In February 1996, a peer review was conducted to assess the implementation of the IPEEE-Seismic program at North Anna. This review included walkdown of about 20% of the items representing all classes of equipment in the SSEL. Although a few open issues were noted at the time of the review, the reviewer concluded that the SRTs involved did an excellent seismic walkdown review at North Anna.

Based on the walkdowns, analyses, and design modification efforts conducted for IPEEE -Seismic, it is concluded that the HCLPF capacities of components, systems and structures at North Anna Power Station Units 1 and 2 are at or above the RLE level, with the exception of a few components whose capacities are less than 0.3 g pga, but above the plant Safe Shutdown Earthquake (SSE) level.

Fire PRA Reference 3 documented the original IPEEE fire analysis for North Anna. It screened out all but four areas as insignificant contributors to core damage risk. These areas included: the Cable Vault and Tunnel (fire area 3-1), Emergency Switchgear room (fire area 6-1), The Main Control Room (fire area 2), and Auxiliary Building (fire area 11).

The NAPS fire PRA model was developed using the following approach:

Fire areas of potential risk significance were identified using the initial qualitative and quantitative screening steps defined in the FIVE methodology [Ref. 8] document.

Those fire areas which did not screen out were subject to detailed modeling described in various procedure guides such as NUREG-2300 [Ref. 10], NUREG-2815 [Ref. 12] or NSAC-181 [Ref. 13]. The COMPBRN IIle code [Ref. 14] was used for all deterministic modeling of intra-area fire propagation.

Inter-area fire propagation analysis was not required based on the review of the fire area boundaries performed to address the Fire Risk Scoping Study, NUREG/CR-5088 [Ref. 15] issues.

Fire frequencies in particular locations accounted for both generic experience (US plant experience obtained from the EPRI Fire Event Data Base) and area specific fixed ignition sources. The contribution of transient fuels and sources was accounted for by addressing plant specific procedures for the control of combustibles and ignition sources, as well as for periodic inspections for transients.

No credit was taken in the analysis for the detection and suppression of fires (Le., fires were allowed to burn until they self extinguished).

Fire Risk Scoping Study Issues were addressed through specifically tailored walkdowns as defined in the FIVE methodology, including seismic fire interactions, effects of fire suppressant on safety related equipment, fire barrier effectiveness and control systems interactions.

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

Serial NO.1 0-122 Docket Nos. 50-338/50-339 Page 140f 15 High Winds / Tornadoes: The NAPS IPEEE results show that the design wind loadings used for North Anna compare favorably with the values presented in the design standard. Therefore, the wind loading design for North Anna is considered to meet the 1975 Standard Review Plan. High winds are therefore judged to contribute less than 1E-6 to the core damage frequency and the IPEEE screening. In addition for tornados, the NAPS IPEEE considers requirements in the 1975 version of the SRP and the majority of the requirements in the current version of the SRP. This fact combined with the considerations of tornado occurrence frequency and contribution to loss of offsite power leads to the conclusion that North Anna is adequately designed against tornado winds.

Therefore, the station does not possess a vulnerability to high winds or tornados Transportation and Nearby Facility Accidents: The IPEEE identifies that the frequency of Transportation and Nearby Facility accidents is concluded to be acceptably low. Transportation and nearby hazards were screened from further consideration in the IPEEE.

Extreme Floods: The NAPS IPEEE for the external flood design at North Anna has shown that the design is comprehensive and adequately accounts for the flooding discussed in SRP Section 2.4. While it cannot be proven that the plant meets the 1975 SRP design criteria, the evidence is sufficient to conclude that flooding of the reservoir or Lake Anna is not vulnerability.

A very detailed maximum probable flood analysis has been completed for Lake Anna.

The effects of the revised PMP design criteria were considered qualitatively and it was shown that susceptible structures are not likely to be impacted by heavier rainfalls occurring for shorter periods of time. Also, adequate protective features are available to divert excess water from the reservoirs and to mitigate the effects of a structural failure.

The SW reservoir is designed with adequate freeboard and has an existing emergency dike and intercepting channel to safely divert a breach flow rate.

Summary of External Event Status As stated earlier, the NEI 04-10, Revision 1 methodology allows for STI change evaluations to be performed in the absence of quantifiable PRA models for all external hazards. Therefore, in performing the assessments for the other hazard groups, a qualitative or bounding approach will be utilized in most cases.

This approach is consistent with the accepted NEI 04-10, Revision 1 methodology.

Summary The NAPS PRA technical capability evaluations and the maintenance and update processes described above provide a robust basis for concluding that the full power internal events NAPS PRA is suitable for use in risk-informed processes such as that proposed for the implementation of a Surveillance Frequency Control Program. In performing the assessments for the other hazard groups, the qualitative or bounding approach will be utilized in most cases. Also, in addition to the standard set of sensitivity studies required per the NEI 04-10, Revision 1 methodology, open items for changes at the site and remaining gaps to specific requirements in the PRA standard will be

Serial No.10-122 Docket Nos. 50-338/50-339 Page 15 of 15 reviewed to determine which, if any, would merit application-specific sensitivity studies in the presentation of the application results.

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.

"Individual Plant Examination Of Non-Seismic External Events And Fires - North Anna Power Station Units 1 And 2," Virginia Electric And Power Company, 1994 4.

"North Anna Power Station Units 1 and 2 Report on Individual Plant Examination of External Events (IPEEE) - Seismic Prepared in Response to USNRC Generic Letter 88-20 Supplements 4 and 5," May 1997 5.

North Anna Power Station Probabilistic Safety Assessment Peer Review Certification Report, July, 2001 6.

North Anna Power Station Units 1 and 2 Probabilistic Risk Assessment Model Notebook Part IV, Appendix A.1, "Internal Events Model Independent Assessment," August 2007 7.

Letter from Mr. Stephen R. Monarque (USNRC) to Mr. David A. Christian, Virginia Electric Power Company, North Anna Power Station, Units 1 and 2 -

Review of Individual Plant Examination of External Events (IPEEE) (TAC NOS.

M83647 and M3648).

8.

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

Methodology Plant Screening

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

9.

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

10.

NUREG-2300, NRC (U.S.

Nuclear Regulatory Commission),

1983.

PRA Procedures Guide, NUREG/CR-2300, American Nuclear Society and Institute of Electrical and Electronic Engineers, January 11.

NUREG-1407, Procedural and Submittal Guidance for the Individual Plant Examination 12.

NUREG-2815, NRC (U.S. Nuclear Regulatory Commission), 1985. Probabilistic Safety Analysis Procedures Guide. NURGE/CR-2815, Brookhaven National Laboratory, Vols. 1 and 2, August 13.

NSAC-181, Nuclear Safety Analysis Center (NSAC), Electric Power Research Institute, Fire PRA Requantification Studies, Palo Alto, CA, January 14.

COMPBRN, Electric Power Research Institute, "Oconee PRA, A Probabilistic Risk Assessment of Oconee Unit 3," NSAC-60, Palo Alto, California, 1994.

15.

NUREG/CR-5088, NRC (U.S. Nuclear Regulatory Commission), 1989. Fire Risk Scoping Study, Sandia National Laboratory, January

Serial No.10-122 Docket Nos. 50-338/339 LAR - Relocate Surveillance Frequencies from TS ATTACHMENT 3 MARKED-UP TECHNICAL SPECIFICATION PAGE CHANGES VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

NORTH ANNA POWERSTATION UNITS 1 AND 2

.INSERTS FORTECHNICAL SPECIFICATIONS MARKUPS (TSCR N-079)

INSERT 1 In accordance with the Surveillance Frequency Control Program INSERT 2 5.5.17 Surveillance Frequency Control Program This program provides controls for Surveillance Frequencies. The program shall ensurethat Surveillance Requirements specified in the Technical Specification are performed at intervals sufficient to assure the associated Limiting Conditions for Operation are met.

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

b. Changes to the Frequencies listed in the Surveillance frequency Control Program shall be made in accordance with NEI04-10, "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.

SDM 3.1.1 3.1 REACTIVITY CONTROL SYSTEMS 3.1.1 SHUTDOWN MARGIN (SDM)

LCO 3.1.1 SDM shall be within the limits provided in the COLR.

APPLICABILITY:

MODE 2 with kef f < 1.0, MODES 3, 4, and 5.

ACTIONS CONDITION A.

SDM not within limit.

A.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE REQUIRED ACTI ON Initiate boration to restore SDM to within 1imi to COMPLETION TIME 15 minutes FREQUENCY SR 3.1.1.1 Verify SDM to be within limits.

24 North Anna Units 1 and 2 3.1.1-1 Amendments 231/212

SURVEILLANCE REQUIREMENTS SURVEILLANCE Core Reactivity 3.1.2 FREQUENCY SR 3.1. 2.1

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

The predicted reactivity values may be adjusted (normalized) to correspond to the measured core reactivity prior to exceeding a fuel burnup of 60 effective full power days (EFPD) after each fuel loading.

Verify measured core reactivity is within

+/- 1% ~k/k of predicted values.

Once prior to entering MODE 1 after each refueling AND

NOTE------

Only required after 60 EFPD North Anna Units 1 and 2 3.1.2-2 Amendments 231/212

Rod Group Alignment Limits 3.1.4 ACTIONS CONDITION D.

More than one rod not within alignment 1imi t.

REQUIRED ACTI ON D.1.1 Verify SDM to be within the limit provided in the COLR.

OR D.1.2 Initiate boration to restore required SDM to within limit.

COMPLETION TIME 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 1 hour SURVEILLANCE REQUIREMENTS AND D.2 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months SR 3.1.4.1 SR 3.1.4.2 SR 3.1.4.3 SURVEILLANCE Verify individual rod positions within alignment limit.

Verify rod freedom of movement (trippability) by moving each rod not fully inserted in the core 2 10 steps in either direction.

Verify rod drop time of each rod, from the fully withdrawn position, is

~ 2.7 seconds from the beginning of decay of stationary gripper coil voltage to dashpot entry, with:

a; Tavg 2 500°F; and

b. All reactor coolant pumps operating.

FREQUENCY 12 R61:IJOS

"~\\~-rlnsert 1 I

92 elays

~Insert 1 I Prior to reactor critica1ity after each removal of the reactor head North Anna Units 1 and 2 3.1.4-3 Amendments 231/212

Shutdown Bank Insertion Limits 3.1.5 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B.

One shutdown bank B.1 Verify SDM to be Once per inserted

~ 18 steps within the limits 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months below the insertion provided in the COLR.

limit and immovable.

AND AND B.2 Restore the shutdown 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Each control and bank to withi n shutdown rod within inserti on 1imi t.

limits of LCO 3.1.4.

AND Each control bank within the insertion limits of LCO 3.1.6.

C.

Required Action and C.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Ti me not met.

SURVEILLANCE REQUIREMENTS SR 3.1. 5.1 SURVEILLANCE Verify each shutdown bank is within the insertion limits specified in the COLR.

FREQUENCY

'~Insert 1 I North Anna Units 1 and 2 3.1.5-2 Amendments 231/212

Control Bank Insertion Limits 3.1.6 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.6.2 Verify each control bank is within the insertion limits specified in the COLR.

12 SR 3.1.6.3 Verify each control bank not fully withdrawn from the core is within the sequence and overlap limits specified in the COLR.

12 ROl:1r5

~Insert 1 North Anna Units 1 and 2 3.1.6-3 Amendments 231/212

Rod Position Indication 3.1. 7 ACTIONS CONDITION REQUIRED ACTI ON COMPLETION TIME D.

One demand position 0.1.1 Verify by Once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months indicator per bank administrative means inoperable for one or all RPIs for the more banks.

affected banks are OPERABLE.

AND 0.1. 2 Verify the most Once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months withdrawn rod and the least withdrawn rod of the affected banks are

~ 12 steps apart.

OR 0.2 Reduce THERMAL POWER 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months to

~ 50% RTP.

E.

Required Action and E.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met.

SURVEILLANCE REQUIREMENTS SR 3.1.7.1 SURVEILLANCE Perform CHANNEL CALIBRATION of each RPI.

FREQUENCY North Anna Units 1 and 2 3.1.7-3 Amendments 231/212

PHYSICS TESTS Exceptions-MODE 2 3.1.9 ACTIONS CONDITION D.

Required Action and D.1 associated Completion Time of Condition C not met.

SURVEILLANCE REQUIREMENTS SURVEILLANCE REQUIRED ACTION Be in MODE 3.

COMPLETION TIME 15 minutes FREQUENCY SR 3.1.9.1 SR 3.1.9.2 SR 3.1. 9.3 SR 3.1. 9.4 Perform a CHANNEL OPERATIONAL TEST on power range and intermediate range channels per SR 3.3.1.7, SR 3.3.1.8, and Table 3.3.1-1.

Verify the RCS lowest loop average temperature is 2 531°F.

Verify THERMAL POWER is

~ 5% RTP.

Verify SDM to be within the limits provided in the COLR.

Prior to initiation of PHYSICS TESTS

..,/\\

~v ~;nsert 1 I

\\-Hnsert 1 I

'~Insert 1 I North Anna Units 1 and 2 3.1.9-2 Amendments 231/212

SURVEILLANCE REQUIREMENTS SURVEILLANCE FQ(Z) 3.2.1 FREQUENCY SR 3.2.1.1

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

If F~(Z) measurements indicate

[

F~(Z)]

maximum over z K(Z) has increased since the previous evaluation of F~ (Z) :

a. Increase F~(Z) by the appropriate factor and verify F~(Z) is still within 1imi ts; or

b. Repeat SR 3.2.1.1 once per 7 EFPD until two successive flux maps indicate

[

F~(Z)]

maximum over z K(Z) has not increased.

Verify F~(Z) is within limit.

Once after each refueling prior to TH ERMAL POWER exceeding 75% RTP AND Once within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after achieving equilibrium conditi ons after exceeding, by 2 10% RTP, the THERMAL POWER at whi ch F~ (Z) was last verified AND North Anna Units 1 and 2 3.2.1-3

ACTIONS N

Ft>H 3.2.2 CONDITION REQUIRED ACTION COMPLETION TIME A.

(continued)

A.4

NOTE---------

THERMAL POWER does not have to be reduced to comply with this Required Action.

Perform SR 3.2.2.1.

Prior to THERMAL POWER exceeding 50% RTP AND Prior to THERMAL POWER exceeding 75% RTP AND 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after THERMAL POWER reaching

~ 95% RTP B.

Required Action and B.1 Be in MODE 2.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met.

SURVEILLANCE REQUIREMENTS SR 3.2.2.1 SURVEILLANCE Verify F1H is within limits specified in the COLR.

FREQUENCY Once after each refueling prior to THERMAL POWER exceeding 75% RTP AND North Anna Units 1 and 2 3.2.2-2

AFD 3.2.3 3.2 POWER DISTRIBUTION LIMITS 3.2.3 AXIAL FLUX DIFFERENCE (AFD)

LCO 3.2.3 The AFD in %flux difference units shall be maintained within the limits specified in the COLR.

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

The AFD shall be considered outside limits when two or more OPERABLE excore channels indicate AFD to be outside limits.

APPLICABILITY:

MODE 1 with THERMAL POWER

~ 50% RTP.

ACTIONS CONDITION A.

AFD not within limits.

A.l SURVEILLANCE REQUIREMENTS SURVEILLANCE REQUIRED ACTION Reduce THERMAL POWER to < 50% RTP.

COMPLETION TIME 30 minutes FREQUENCY SR 3.2.3.1 Verify AFD within limits for each OPERABLE

+7~~

excore channel.

North Anna Units 1 and 2 3.2.3-1 Amendments 2~1/212

ACTIONS QPTR 3.2.4 CONDITION REQU IRED ACTI ON COMPLETION TIME A.

(continued)

A.6

NOTE---------

Perform Required Action A.6 only after Required Action A.5 is completed.

Perform SR 3.2.1.1 and Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months SR 3.2.2.1.

after achieving equilibrium Conditions at RTP not to exceed 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months after increasing THERMAL POWER above the limit of Required Action A.1 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 ::; 50% RTP.

Ti me not met.

SURVEILLANCE REQUIREMENTS SR 3.2.4.1 SURVEILLANCE

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

1. With input from one Power Range Neutron Flux channel inoperable and THERMAL POWER::; 75% RTP, the remaining three power range channels can be used for calculating QPTR.

2. SR 3.2.4.2 may be performed in lieu of this Surveillance.

Verify QPTR is within limit by calculation.

FREQUENCY North Anna Units 1 and 2 3.2.4-3 Amendments 231/212

SURVEILLANCE REQUIREMENTS SURVEILLANCE QPTR 3.2.4 FREQUENCY SR 3.2.4.2

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

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after input from one or more Power Range Neutron Flux channels are inoperable with THERMAL POWER> 75% RTP.

Verify QPTR is within limit using the movable incore detectors.

North Anna Units 1 and 2 3.2.4-4 Amendments 231/212

RTS Instrumentation 3.3.1 ACTIONS CONDITION REQU IRED ACTION COMPLETION TIME R.

One or more channels R.1 Verify interlock is in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable.

required state for existi ng unit conditions.

OR R.2 Be in MODE 2.

7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months S.

One trip mechanism S.l Restore inoperable 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months inoperable for one trip mechanism to RTB.

OPERABLE status.

OR S.2 Be in MODE 3.

54 hours6.25e-4 days 0.015 hours 8.928571e-5 weeks 2.0547e-5 months SURVEILLANCE REQUIREMENTS

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

Refer to Table 3.3.1-1 to determine which SRs apply for each RTS Function.

SR 3.3.1.1 SR 3.3.1.2 SURVEILLANCE Perform CHANNEL CHECK.

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 is 2 15% RTP.

Compare results of calorimetric heat balance calculation to power range channel output. Adjust power range output if calorimetric heat balance calculation result exceeds power range channel output by more than +2% RTP.

FREQUENCY 12 R6Ul"S Insert 1 2~.~

Insert 11 North Anna Units 1 and 2 3.3.1-8 Amendment 231/212

SURVEILLANCE REQUIREMENTS SURVEILLANCE RTS Instrumentation 3.3.1 FREQUENCY SR 3.3.1.3 SR 3.3.1.4 SR 3.3.1.5 SR 3.3.1.6 SR 3.3.1.7

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

Not required to be performed until 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months after THERMAL POWER is 2 15% RTP.

Compare results of the incore detector measurements to Nuclear Instrumentation System (NIS) AFD. Adjust NIS channel if absolute difference is 2 3%.

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

This Surveillance must be performed on the reactor trip bypass breaker immediately after placing the bypass breaker in service.

Perform TADOT.

Perform ACTUATION LOGIC TEST.

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

Verification of setpoint is not required.

Perform TADOT.

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

Not required to be performed for source range instrumentation prior to entering MODE 3 from MODE 2 until 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after entry into MODE 3.

Perform COT.

31 effeetive fblll

~g'.'!8r Qa:YS (f:FPQ)

~Insert 1 L

dl says SR a STAGGERED TEST

~

'---Ilnsert 1 I 31 days 01'1 a STAGGERED TEST

~

\\......flnsert 1 I 92 day s

~

"--["Insert 1 I 92 days

~

\\......flnsert 1 I North Anna Units 1 and 2 3.3.1-9 Amendment 2dl/212

RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY the frequency specified in the Perform COT. Surveillance Frequency Control Program

NOTE-----

Only required when not performed withi n I3Fevis1:I5 92 days

~-------------

.:>> Prior to reactor startup

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

This Surveillance shall include verification that interlocks P-6 and P-10 are in their required state for existing unit conditions.

SR 3.3.1.8 AND Four hours after reducing power below P-6 for source range instrumentation AND Twelve hours after reduci ng power below P-10 for power and intermediate range instrumentation AND 019 ce \\3el" 92 says tRel"~ftel" SR 3.3.1.9

'----Ilnsert 1 I

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

1. Adjust NIS channel if absolute difference:?: 3%.

2. Not required to be performed until 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months after THERMAL POWER is

?: 50% RTP.

Compare results of the excore channels to incore detector measurements.

92 f:rPQ

'~Insert 1 I North Anna Units 1 and 2 3.3.1-10 Amendment 231/212

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.3.1.10

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

This Surveillance shall include verification that the time constants are adjusted to the prescribed values.

Perform CHANNEL CALIBRATION.

SR 3.3.1.11

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

Neutron detectors are excluded from CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION.

SR 3.3.1.12 Perform CHANNEL CALIBRATION.

SR 3.3.1.13 Perform COT.

RTS Instrumentation 3.3.1 FREQUENCY

'--Ilnsert 1 I Ylnsert 1 I SR 3.3.1.14

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

Verification of setpoint is not required.

Perform TADOT.

'--II nsert 1 I SR 3.3.1.15

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

Verification of setpoint is not required.

Perform TADOT.

~-f1 nsert 1 I Prior to exceeding the P-8 interlock whenever the unit has been in MODE 3, if not performed wi thi n the previous 31 days North Anna Units 1 and 2 3.3.1-11 Amendment 231/212

RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.3.1.16

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

Neutron detectors are excluded from response time testing.

FREQUENCY Verify RTS RESPONSE TIME is within limits.

18 ffi6RtAS SR a STA66EREf> TEST

""B1mS Insert 1 North Anna Units 1 and 2 3.3.1-12 Amendment 231/212

ESFAS Instrumentation 3.3.2 ACTIONS CONDITION REQUIRED ACTI ON COMPLETION TIME J.

One or more channels inoperable.

J.1 Verify interlock is in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months required state for existing unit conditi on.

OR J.2.1 Be in MODE 3.

7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months AND J.2.2 Be in MODE 4.

13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months SURVEILLANCE REQUIREMENTS

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

Refer to Table 3.3.2-1 to determine which SRs apply for each ESFAS Function.

SURVEILLANCE FREQUENCY SR 3.3.2.1 Perform CHANNEL CHECK.

SR 3.3.2.2 Perform ACTUATION LOGIC TEST.

'-IInsert 1 I 31 days SA a STAGGERED TEST

&A5iS,\\

,Insert 1 I

92 da~s

'--11nsert 1 I 31 days SA a STAGGERED TEST

-BA£f5,\\

Perform COT Perform MASTER RELAY TEST.

SR 3.3.2.3 SR 3.3.2.4

\\.......flnsert 1 I North Anna Units 1 and 2 3.3.2-5 Amendments 231/212

SURVEILLANCE ESFAS Instrumentation 3.3.2 FREQUENCY SR 3.3.2.5

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

Not required to be performed for SLAVE RELAYS if testing would:

1. Result in an inadvertent Reactor Trip System or ESFAS Actuation if accompanied by a single failure in the Safeguard Test Cabinet;

2. Adversely affect two or more components in one or more ESFAS system(s); or

3. Create a reactivity, thermal, or hydraulic transient condition in the Reactor Coolant System.

SR 3.3.2.6 SR 3.3.2.7 SR 3.3.2.8 Perform SLAVE RELAY TEST.

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

Verification of relay setpoints not required.

Perform TADOT.

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

Verification of setpoint not required for manual initiation or interlock functions.

Perform TADOT.

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

This Surveillance shall include verification that the time constants are adjusted to the prescribed values.

Perform CHANNEL CALIBRATION.

92 says

~

\\....{Insert 1 I

\\.......flnsert 1 I 18 IflSRtRS

~

"-[Insert 1 I Ylnsert 1 I North Anna Units 1 and 2 3.3.2-6 Amendments 244/225

SURVEILLANCE ESFAS Instrumentation 3.3.2 FREQUENCY SR 3.3.2.9

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

Not required to be performed for the turbine driven AFW pump until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after SG pressure is

~ 1005 psig.

Verify ESFAS RESPONSE TIMES are within limit.

18 ffiSAtRS SA a STAGGERED TES:r ftfI:StS North Anna Units 1 and 2 3.3.2-7 Amendments 244/~~5

PAM Instrumentation 3.3.3 SURVEILLANCE REQUIREMENTS

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

SR 3.3.3.1 and SR 3.3.3.3 apply to each PAM instrumentation Function in Table 3.3.3-1 except SR 3.3.3.3 does not apply to Item 10. SR 3.3.3.4 applies,f only to Item 10.

SR 3.3.3.1 SR 3.3.3.2 SR 3.3.3.3 SR 3.3.3.4 SURVEILLANCE Perform CHANNEL CHECK for each required instrumentation channel that is normally energized.

Not Used

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

Neutron detectors are excluded from CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION.

Perform TADOT.

FREQUENCY 31 dB:) 3

~Insert 1

'----1lnsert 1 I 18 IflORtl:1S

'----1lnsert 1 I North Anna Units 1 and 2 3.3.3-2 Amendments 238/219

Remote Shutdown System 3.3.4 3.3 INSTRUMENTATION 3.3.4 Remote Shutdown System LCO 3.3.4 The Remote Shutdown System Functions shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS

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

Separate Condition entry is allowed for each Function.

CONDITION REQU IRED ACTI ON COMPLETION TIME A.

One or more required A.1 Restore required 30 days Functions inoperable.

Function to OPERABLE status.

B.

Required Action and B.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met.

AND B.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SURVEILLANCE REQUIREMENTS SR 3.3.4.1 SR 3.3.4.2 SURVEILLANCE Perform CHANNEL CHECK for each required instrumentation channel that is normally energized.

Verify each required control circuit and transfer switch is capable of performing the intended function.

FREQUENCY 31 says

'-1lnsert 1 18 mORtRs

'-1lnsert 1 North Anna Units 1 and 2 3.3.4-1 Amendments 231/212

SURVEILLANCE REQUIREMENTS SURVEILLANCE Remote Shutdown System 3.3.4 FREQUENCY SR 3.3.4.3 Perform CHANNEL CALIBRATION for each required instrumentation channel.

North Anna Units 1 and 2 3.3.4-2 Amendments 231/212

LOP EDG Start Instrumentation 3.3.5 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C.

Required Action and C.1 associated Completion Time not met.

SURVEILLANCE REQUIREMENTS Enter applicable Immediately Condition(s) and Required Action(s) for the associated EDG made inoperable by LOP EDG start instrumentation.

North Anna Units 1 and 2

,Insert 1 I Amendments 2dl/212 SR 3.3.5.1 SR 3.3.5.2 SR 3.3.5.3 SURVEILLANCE

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

Verification of setpoint is not required.

Perform TADOT for LCO 3.3.5.a and LCO 3.3.5.b Functions.

Perform CHANNEL CALIBRATION with Allowable Values as follows:

a. Loss of voltage Allowable values > 2935 V and

~ 3225 Vwith a time delay of 2 +/-1 seconds for LCO 3.3.5.a and LCO 3.3.5.b Functions.

b. Degraded voltage Allowable Values

~ 3720 V and

~ 3772 Vwith:

1. A time delay of 7.5 +/-1.5 seconds with a Safety Injection (SI) signal for LCO 3.3.5.a Function; and

2. A time delay of 56 +/-7 seconds without an SI signal for LCO 3.3.5.a and LCO 3.3.5.b Functions.

Verify ESF RESPONSE TIMES are within limit for LCO 3.3.5.a and LCO 3.3.5.b Functions~

3.3.5-2 FREQUENCY n'l

.J

-'--rlnsert 1 I 18 montns

~Insert 1 18 1f161'1t~S 61'1 a ST,o.(;;(;;~R~Q HS:r nftC'TC'

~

.~~~ ~

MCR/ESGR Envelope Isolation Actuation Instrumentation 3.3.6 SURVEILLANCE REQUIREMENTS SR 3.3.6.1 SURVEILLANCE

~---NOTE-------------------

Verification of setpoint is not required.

Perform TADOT.

FREQUENCY North Anna Units 1 and 2 3.3.6-2 Amendments 255/236

RCS Pressure, Temperature, and Flow DNB Limits 3.4.1 SURVEILLANCE REQUIREMENTS SR 3.4.1.1 SR 3.4.1.2 SR 3.4.1.3 SR 3.4.1.4 SURVEILLANCE Verify pressurizer pressure is greater than or equal to the limit specified in the COLR.

Verify RCS average temperature is less than or equal to the limit specified in the COLR.

Verify RCS total flow rate is 2 295,000 gpm and is greater than or equal to the limit specified in the COLR.

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

Not required to be performed until 30 days after 2 90% RTP.

Verify by precision heat balance that RCS total flow rate is 2 295,000 gpm and is greater than or equal to the limit specified in the COLR.

FREQUENCY 12 A61:11"S

~Insert 1 12 i'l61:11"3

~Insert 1 12 A61:11"S

~Insert 1 10 mOlitli~

~Insert 1 North Anna Units 1 and 2 3.4.1-2 Amendments 231/212

RCS Minimum Temperature for Criticality 3.4.2 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.2 RCS Minimum Temperature for Criticality LCO 3.4.2 Each RCS loop average temperature (Tavg) shall be

~ 541°F.

APPLICABILITY:

MODE 1, MODE 2 with keff

~ 1.O.

ACTIONS CONDITION A.

Tav in one or more Rc§9 loops not within 1imi t.

SURVEILLANCE REQUIREMENTS A.l REQUIRED ACTI ON Be in MODE 2 with keff < 1.0.

COMPLETION TIME 30 minutes SURVEILLANCE FREQUENCY SR 3.4.2.1 Verify RCS TavQ in each loop

~ 541°F.

12 North Anna Units 1 and 2 3.4.2-1 Amendments 231/212

ACTIONS CONDITION C.

NOTE---------

C.1 Required Action C.2 shall be completed whenever this Condition is entered.

AND C.2 Requirements of LCO not met any time in other than MODE 1, 2, 3, or 4.

SURVEILLANCE REQUIREMENTS SURVEILLANCE REQUIRED ACTION Initiate action to restore parameter(s) to within limits.

Determine RCS is acceptable for continued operation.

RCS P/T Limits 3.4.3 COMPLETION TIME Immediately Prior to entering MODE 4 FREQUENCY SR 3.4.3.1

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

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

Verify RCS pressure, RCS temperature, and RCS heatup and cool down rates are within limits.

30 111;litlte5

'-1lnsert 1 North Anna Units 1 and 2 3.4.3-2 Amendments 231/212

RCS Loops-MODES 1 and 2 3.4.4 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.4 RCS Loops-MODES 1 and 2 LCO 3.4.4 Three RCS loops shall be OPERABLE and in operation.

APPLICABILITY:

MODES 1 and 2.

ACTIONS CONDITION A.

Requirements of LCO not met.

SURVEILLANCE REQUIREMENTS A.l REQUIRED ACTI ON Be in MODE 3.

COMPLETION TIME 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months SURVEILLANCE FREQUENCY SR 3.4.4.1 Verify each RCS loop is in operation.

North Anna Units 1 and 2 3.4.4-1 Amendments 231/212

RCS Loops-MODE 3 3.4.5 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C.

Two required RCS loops C.1 Place the Rod Control Immediately inoperable.

System in a condition incapable of rod OR withdrawal.

Required RCS loop not AND in operation.

C.2 Suspend operations Immediately that would cause introduction into the RCS, coolant with boron concentration less than required to meet SDM of LCO 3.1.1.

AND C.3 Initiate action to Immediately restore one RCS loop to OPERABLE status and operation.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.5.1 Verify required RCS loops are in operation.

12 IIOtH S

~

---,Insert 1 I 12 I:lel-:l~-nnsert 1 I 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 a required pump is not in operation.

Verify steam generator secondary side water levels are 2 17% for required RCS loops.

SR 3.4.5.2 SR 3.4.5.3 Verify correct breaker alignment and indicated power are available to the required pump not in operation.

7 days

~Insert 1 North Anna Units 1 and 2 3.4.5-2 Amendments 231/212

ACTIONS RCS Loops-MODE 4 3.4.6 CONDITION B.

Two required loops inoperable.

OR Required loop not in operation.

REQUIRED ACTION COMPLETION TIME B.1 Suspend operations Immediately that would cause introduction into the RCS, coolant with boron concentration less than required to meet SDM of LCO 3.1.1.

AND B.2 Initiate action to Immediately restore one loop to OPERABLE status and operation.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.6.1 Verify required RHR or RCS loop is in operation.

1?

("...

,~r

~Jlnsert 1 I SR 3.4.6.2 SR 3.4.6.3 Verify SG secondary side water levels are

~ 17% for required RCS loops.

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

Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after a required pump is not in operation.

12 "'el:l'fS

\\

Insert 1 I Verify correct breaker alignment and indicated power are available to the required pump not in operation.

7 says

'-1lnsert 1 North Anna Units 1 and 2 3.4.6-2 Amendments 231/212

RCS Loops-MODE 5, Loops Filled 3.4.7 SURVEILLANCE REQUIREMENTS SR 3.4.7.1 SR 3.4.7.2 SR 3.4.7.3 SURVEILLANCE Verify required RHR loop is in operation.

Verify SG secondary side water level is

~ 17% in required SG.

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

Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after a required pump is not in operation.

Verify correct breaker alignment and indicated power are available to the required RHR pump not in operation.

FREQUENCY 12~

Ylnsert 1 I 12 hmtrs

-\\

Insert 1 I 7~

'-1lnsert 1 North Anna Units 1 and 2 3.4.7-3 Amendments 231/212

RCS Loops-MODE 5, Loops Not Filled 3.4.8 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B.

No required RHR loop B.1 OPERABLE.

OR Required RHR loop not in operation.

AND Suspend operations Immediately that would cause introduction into the RCS, coolant with boron concentration less than required to meet SDM of LCO 3.1.1.

B.2 Initiate action to Immediately restore one RHR loop to OPERABLE status and operation.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.8.1 SR 3.4.8.2 Verify required RHR loop is in operation.

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

Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after a required pump is not in operation.

12 Verify correct breaker alignment and indicated power are available to the required RHR pump not in operation.

North Anna Units 1 and 2 3.4.8-2 Amendments 231/212

SURVEILLANCE REQUIREMENTS SURVEILLANCE Pressurizer 3.4.9 FREQUENCY SR 3.4.9.1 SR 3.4.9.2 Verify pressurizer water level is

~ 93%.

Verify capacity of each required group of pressurizer heaters is 2 125 kW.

12 Insert 1 North Anna Units 1 and 2 3.4.9-2 Amendments 231/212

ACTIONS Pressurizer PORVs 3.4.11 CONDITION REQUIRED ACTION COMPLETION TIME G.

Two block valves G.1

NOTE---------

inoperable.

Required Action G.1 does not apply when block valve is inoperable solely as a result of complying with Requi red Action C.2.

Restore one block 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months valve to OPERABLE status.

H.

Required Action and H.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition G AND not met.

H.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SURVEILLANCE REQUIREMENTS SURVEI LLANCE FREQUENCY SR 3.4.11.1 Verify PORV backup nitrogen supply pressure is within limit.

Insert 1 SR 3.4.11.2

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

1. Not required to be performed with block valve closed in accordance with the Required Actions of this LCO.

2. Only reqUired to be performed in MODES 1 and 2.

Perform a complete cycle of each block valve.

92 e1a\\

Insert 1 I North Anna Units 1 and 2 3.4.11-3 Amendments 231/212

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.4.11.3

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

Only required to be performed in MODES 1 and 2.

Perform a complete cycle of each PORV.

SR 3.4.11.4 Perform a complete cycle of each solenoid control valve and check valve on the accumulators in PORV control systems.

Pressurizer PORVs 3.4.11 FREQUENCY North Anna Units 1 and 2 3.4.11-4 Amendments 231/212

ACTIONS CONDITION G.

Two required PORVs inoperable.

OR Required Action and associated Completion Time of Condition A, B, D, E, or F not met.

OR LTOP System inoperab1e for any reason other than Condition A, B, C, D, E, or F.

SURVEILLANCE REQUIREMENTS G.1 REQUIRED ACTI ON Depressurize RCS and establish RCS vent of

~ 2.07 square inches.

LTOP System 3.4.12 COMPLETION TIME 12 1:101::11"5

'--!Insert 1 SURVEILLANCE SR 3.4.12.1 Verify a maximum of one LHSI pump is capable of injecting into the RCS.

SR 3.4.12.2 Verify a maximum of one charging pump is capable of injecting into the RCS.

SR 3.4.12.3

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

Only required to be met if accumulator pressure is greater than PORV lift setting.

Verify each accumulator is isolated and power is removed from the accumulator isolation valve operator.

FREQUENCY 12 hOUi~'\\

Insert 1 I 12 I'lSl:ll"S, Insert 1 I 12 I'lSl:ll"S

'--!Insert 1 North Anna Units 1 and 2 3.4.12-3 Amendments 231/212

SURVEILLANCE REQUIREMENTS LTOP System 3.4.12 SURVEILLANCE FREQUENCY SR 3.4.12.4 Verify required RCS vent

~ 2.07 square 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for inches open.

unlocked open vent valve(s)

AND 31 e1ays fer etAcr "CAt

~\\

Insert 1 I SR 3.4.12.5 Verify PORV block valve is open for each 72 Ael:lrS required PORV and PORV keyswitch is in

~Insert 1 AUTO.

I SR 3.4.12.6 Verify required PORV backup nitrogen supply 7 days pressure is within limit.

~

,Insert 1 I SR 3.4.12.7

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

Not required to be met until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after decreasing RCS cold leg temperature to

280°F.

Perform a COT on each required PORV, 31 8\\

excluding actuation.

Insert 1 I SR 3.4.12.8 Perform CHANNEL CALIBRATION for each 10 mo,115 required PORV actuation channel.

I Insert 1 North Anna Units 1 and 2 3.4.12-4 Amendments 242/223

RCS Operational LEAKAGE 3.4.13 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.13.1

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

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

2. Not applicable to primary to secondary LEAKAGE.

Insert 1 72 1'H3l:1fS

~Insert 1 Veri fy primary to secondary LEAKAGE is 72

~Ol:lrtS

~ 150 gallons per day through anyone SG.

Verify RCS operational LEAKAGE is within limits by performance of RCS water inventory balance.

SR 3.4.13.2

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

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

ir

================~==:k~~-,

North Anna Units 1 and 2 3.4.13-2 Amendments 248/228

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.4.14.1

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

1. Not required to be performed in MODES 3 and 4.

2. Not required to be performed on any RCS PIVs required to be tested located in the RHR flow path when in the shutdown cooling mode of operation.

3. RCS PIVs actuated during the performance of this Surveillance are not required to be tested more than once if a repetitive testing loop cannot be avoided.

Verify leakage from each RCS PIV required to be tested is equivalent to

~ 0.5 gpm per nominal inch of valve size up to a maximum of 5 gpm at an RCS pressure 2 2215 psig and

~ 2255 psig.

RCS PIV Leakage 3.4.14 FREQUENCY In accordance with the Inservice Testing Program, and 18 mOI,th~

AND

'--!Insert 1 Prior to enteri ng MODE 2 whenever the unit has been in MODE 5 for 7 days or more, if 1eakage testi ng has not been performed in the previous 9 months AND Withi n 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months following valve actuation due to automatic or manual action or flow through the valve North Anna Units 1 and 2 3.4.14-2 Amendments 231/212

RCS Leakage Detection Instrumentation 3.4.15 SURVEILLANCE REQUIREMENTS SR 3.4.15.1 SR 3.4.15.2 SR 3.4.15.3 SR 3.4.15.4 SURVEILLANCE Perform CHANNEL CHECK of the required containment atmosphere radioactivity monitor.

Perform COT of the required containment atmosphere radioactivity monitor.

Perform CHANNEL CALIBRATION of the required containment sump monitor.

Perform CHANNEL CALIBRATION of the required containment atmosphere radioactivity monitor.

FREQUENCY 1~

liOt1i S

~lnsert1 92 days

~lnsert1 18 ~r:-----..,.-....,....

'~lnsert1 18 m~s

, ~~In-s-ert---""-1-1 North Anna Units 1 and 2 3.4.15-3 Amendments 231/212

RCS Specific Activity 3.4.16 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY Verify reactor coolant DOSE EQUIVALENT 1-131 specific activity

~ 1.0

~Ci/gm.

Verify reactor coolant DOSE EQUIVALENT XE-133 specific activity

~ 197

~Ci/gm.

SR 3.4.16.2 SR 3.4.16.1 7 days~

V----:--:--

. ------rrns-ert 1

1r----------=

14 eays t

AND

"--!Insert 1 Between 2 and 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after a THERMAL POWER change of 2 15% RTP within a 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months period North Anna Units 1 and 2 3.4.16-2 Amendments

RCS Loop Isolation Valves 3.4.17 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.17.2 Verify power removed from each RCS loop

+31~~

isolation valve.

Insert 1 North Anna Units 1 and 2 3.4.17-2 Amendments 231/212

RCS Loops-Test Exceptions 3.4.19 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.19 RCS Loops-Test Exceptions LCO 3.4.19 The requirements of LCO 3.4.4, "RCS Loops-MODES 1 and 2," may be suspended, with THERMAL POWER < P-7.

APPLICABILITY:

MODES 1 and 2 during startup and PHYSICS TESTS.

ACTIONS CONDITION A.

THERMAL POWER

~ P-7.

SURVEILLANCE REQUIREMENTS A.l REQUIRED ACTION Open reactor trip breakers.

COMPLETION TIME Immediately SURVEILLANCE SR 3.4.19.1 Verify THERMAL POWER is < P-7.

SR 3.4.19.2 Perform a COT for each power range neutron flux-low channel, intermediate range neutron flux channel, P-I0, and P-13.

SR 3.4.19.3 Perform an ACTUATION LOGIC TEST on P-7.

FREQUENCY 1 i'lO~

\\........flnsert 1 I Prior to initiation of startup and PHYSICS TESTS Prior to initiation of startup and PHYSICS TESTS North Anna Units 1 and 2 3.4.19-1 Amendments 231/212

SURVEILLANCE REQUIREMENTS SURVEILLANCE Accumulators 3.5.1 FREQUENCY SR 3.5.1.1 Verify each accumulator isolation valve is fully open.

12 R8blr~

'\\

Insert 1 I SR 3.5.1.2 SR 3.5.1.3 SR 3.5.1.4 SR 3.5.1.5 Verify borated water volume in each accumulator is 2 7580 gallons and

7756 gallons.

Verify nitrogen cover pressure in each accumulator is 2 599 psig and::; 667 psig.

Verify boron concentration in each accumulator is 2 2500 ppm and::; 2800 ppm.

Verify power is removed from each accumulator isolation valve operator when RCS pressure is 2 2000 psig.

12 R8blrs

'--11nsert 1 12 Retlrs

~Insert 1 I 31 day:;

...r-AND 1'\\.,.--__

~Insert 1

NOTE------

Only required to be performed for affected accumulators Once within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after each solution vo1ume increase of 2 50% of indi cated 1evel that is not the result of addition from the refueling water storage tank 31 days

'--1lnsert 1 North Anna Units 1 and 2 3.5.1-2 Amendments 231/218

ECCS-Operating 3.5.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.2.1 Verify the following valves are in the 12 1:l81:H'S listed position with power to the valve

~lnsert1 operator removed.

Unit 1 Number Position Function 1-SI-MOV-1890A Closed LHSI to Hot Leg 1-SI-MOV-1890B Closed LHSI to Hot Leg 1-SI-MOV-1836 Closed HHSI Pump to Cold Leg 1-SI-MOV-1869A Closed HHSI Pump to Hot Leg 1-SI-MOV-1869B Closed HHSI Pump to Hot Leg Unit 2 Number Positi on Function 2-SI-MOV-2890A Closed LHSI to Hot Leg 2-SI-MOV-2890B Closed LHSI to Hot Leg 2-SI-MOV-2836 Closed HHSI Pump to Cold Leg 2-SI-MOV-2869A Closed HHSI Pump to Hot Leg 2-SI-MOV-2869B Closed HHSI Pump to Hot Leg SR 3.5.2.2 Verify each ECCS manual, power operated, 31 says and automatic valve in the flow path, that

~Insert1 is not locked, sealed, or otherwise secured in position, is in the correct position.

SR 3.5.2.3 Verify ECCS piping is sufficiently full of 92 SaYS water.

~lnsert1 SR 3.5.2.4 Verify each ECCS pump's developed head at In accordance the test flow point is greater than or with the equal to the required developed head.

Inservice Testing Program North Anna Units 1 and 2 3.5.2-2 Amendments 231/212

SURVEILLANCE REQUIREMENTS SURVEILLANCE ECCS-Operating 3.5.2 FREQUENCY SR 3.5.2.5 SR 3.5.2.6 SR 3.5.2.7 Verify each ECCS automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

Verify each ECCS pump capable of starting automatically starts automatically on an actual or simulated actuation signal.

Verify each ECCS throttle valve listed below is secured in the correct position.

Unit 1 Valve Number Unit 2 Valve Number 18 1f161'lUl:;

~Insert 1 -

18 1f161'lt19s

~Insert 1 -

18 mOlitlis

~Insert 1...,

1-SI-188 1-SI-191 1-SI-193 1-SI-203 1-SI-204 1-SI-205 2-SI-89 2-SI-97 2-SI-103 2-SI-116 2-SI-111 2-SI-123 SR 3.5.2.8 Verify, by visual inspection, each ECCS train containment sump component is not restricted by debris and shows no evidence of structural distress or abnormal corrosion.

18 1f161'lt19S

~Insert 1 ~

North Anna Units 1 and 2 3.5.2-3 Amendments 250/230

SURVEILLANCE REQUIREMENTS RWST 3.5.4 SR 3.5.4.1 SR 3.5.4.2 SR 3.5.4.3 SURVEILLANCE Verify RWST borated water temperature is 240°F and

~ 50°F.

Verify RWST borated water volume is 2 466,200 gallons and

~ 487,000 gallons.

Verify RWST boron concentration is 2 2600 ppm and

~ 2800 ppm.

FREQUENCY 24 R8l:lf'S

'-rlnsert 1 I 7 days

\\. Jlnsert 1 I 7 says

-t

\\

Insert 1 I North Anna Units 1 and 2 3.5.4-2 Amendments 231/218

SURVEILLANCE REQUIREMENTS SURVEILLANCE Seal Injection Flow 3.5.5 FREQUENCY SR 3.5.5.1

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

Not required to be performed until 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after the Reactor Coolant System pressure stabilizes at 2 2215 psig and

~ 2255 psig.

Verify manual seal injection throttle valves are adjusted to give a flow within limit with RCS pressure 2 2215 psig and

~ 2255 psig and the seal injection hand control valve full open.

31 ddyS

'-1lnsert 1 North Anna Units 1 and 2 3.5.5-2 Amendments 231/212

SURVEILLANCE REQUIREMENTS BIT 3.5.6 SR 3.5.6.1 SR 3.5.6.2 SR 3.5.6.3 SURVEILLANCE Verify BIT borated water temperature is Z U5°F.

Verify BIT borated water volume is z 900 gallons.

Verify BIT boron concentration is z 12,950 ppm and

~ 15,750 ppm.

FREQUENCY 24 ROI:H'S

~Insert 1 I 7 says

'--rlnsert 1 I 7 lays

\\

Insert 1 I North Anna Units 1 and 2 3.5.6-2 Amendments 231/212

Containment Air Locks 3.6.2 SURVEILLANCE REQUIREMENTS SR 3.6.2.1 SURVEILLANCE

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

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

2. Results shall be evaluated against acceptance criteria applicable to SR 3.6.1.1.

Perform required air lock leakage rate testing in accordance with the Containment Leakage Rate Testing Program.

FREQUENCY In accordance with the Containment Leakage Rate Testing Program SR 3.6.2.2 Verify only one door in the air lock can be 2~4~~~

opened at a time.

North Anna Units 1 and 2 3.6.2-5 Amendments 231/212

Containment Isolation Valves 3.6.3 SURVEILLANCE REQUIREMENTS SR 3.6.3.1 SR 3.6.3.2 SR 3.6.3.3 SR 3.6.3.4 SURVEILLANCE

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

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

Verify each containment isolation manual valve and blind flange that is located outside containment and not locked, sealed, or otherwise secured and required to be closed during accident conditions is closed, except for containment isolation valves that are open under administrative controls.

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

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

Verify each containment isolation manual valve and blind flange that is located inside containment and not locked, sealed, or otherwise secured and required to be closed during accident conditions is closed, except for containment isolation valves that are open under administrative controls.

Verify the isolation time of each automatic power operated containment isolation valve is within limits.

Perform leakage rate testing for containment purge valves with resilient seals.

FREQUENCY 31~

. ~r-ln-s-e-rt-1 I Prior to entering MODE 4 from MODE 5 if not performed within the previous 92 days In accordance with the Inservice Testing Program Prior to entering MODE 4 from MODE 5 after containment vacuum has been broken North Anna Units 1 and 2 3.6.3-5 Amendments 231/21~

Containment Isolation Valves 3.6.3 SURVEILLANCE REQUIREMENTS SR 3.6.3.5 SR 3.6.3.6 SURVEILLANCE Verify each automatic containment isolation valve that is not locked, sealed or otherwise secured in position, actuates to the isolation position on an actual or simulated actuation signal.

Cycle each weight or spring loaded check valve not testable during operation through one complete cycle of full travel, and verify each check valve remains closed when the differential pressure in the direction of flow is < 1.2 psid and opens when the differential pressure in the direction of flow is 2 1.2 psid and < 5.0 psid.

FREQUENCY 18 mORtRs

'-1lnsert 1 18 mOI,tlls

'-1lnsert 1 North Anna Units 1 and 2 3.6.3-6 Amendments 231/212

Containment Pressure 3.6.4 3.6 CONTAINMENT SYSTEMS 3.6.4 Containment Pressure LCO 3.6.4 Containment air partial pressure shall be within the acceptable operation range shown on Figure 3.6.4-1.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQU IRED ACTI ON COMPLETION TIME A.

Containment air A.l Restore containment 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months partial pressure not air partial pressure within limits.

to within limits.

B.

Required Action and B.l Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met.

AND B.2 Be in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SR 3.6.4.1 SURVEILLANCE Verify containment air partial pressure is within limits.

12 FREQUENCY North Anna Units 1 and 2 3.6.4-1 Amendment Nos. 232/214

Containment Air Temperature 3.6.5 3.6 CONTAINMENT SYSTEMS 3.6.5 Containment Air Temperature LCO 3.6.5 Containment average air temperature shall be

~ 86°F and

~ U5°F.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQU IRED ACTI ON COMPLETION TIME A.

Containment average A.l Restore containment 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months air temperature not average air within limits.

temperature to within limits.

B.

Required Action and B.l Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met.

AND B.2 Be in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.5.1 Verify containment average air temperature

~24~~~

is within limits.

North Anna Units 1 and 2 3.6.5-1 Amendments 250/230

3.6 CONTAINMENT SYSTEMS 3.6.6 Quench Spray (QS) System LCO 3.6.6 Two QS trains shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS QS System 3.6.6 CONDITION REQUIRED ACTION COMPLETION TIME A.

One QS train A.1 Restore QS train to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months inoperable.

OPERABLE status.

B.

Required Action and B.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met.

AND B.2 Be in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SR 3.6.6.1 SR 3.6.6.2 SURVEILLANCE Verify each QS 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.

Verify each QS pump's developed head at the flow test point is greater than or equal to the required developed head.

FREQUENCY 31 lays

'-1lnsert 1 In accordance with the Inservice Testing Program North Anna Units 1 and 2 3.6.6-1 Amendments 231/212

SURVEILLANCE REQUIREMENTS SURVEILLANCE QS System 3.6.6 FREQUENCY SR 3.6.6.3 SR 3.6.6.4 Verify each QS automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

Verify each QS pump starts automatically on an actual or simulated actuation signal.

18 ffiel'lH1S

~Insert 1, I 18 ffie~tl9S

~l":""ln-s-e-rt~1':"""""""11 SR 3.6.6.5 Verify each spray nozzle is unobstructed.

Fo11 owi ng maintenance which could cause nozzle blockage North Anna Units 1 and 2 3.6.6-2 Amendments 233/215

RS System 3.6.7 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME.

F.

One outside RS F.1 subsystem and one inside RS subsystem inoperable and not in the same train.

Enter LCO 3.0.3.

Immediately OR Three or more RS subsystems inoperable.

OR Two outside RS subsystems inoperable.

SURVEILLANCE REQUIREMENTS

-t SURVEILLANCE FREQUENCY SR 3.6.7.1 Verify casing cooling tank temperature is 24 hOtH S

~ 35°F and

~ 50°F.

'-.rlnsert 1 I SR 3.6.7.2 Verify casing cooling tank contained 7 says borated water volume is

~ 116,500 gal.

~Insert1 I SR 3.6.7.3 Verify casing cooling tank boron 7-&a-y-s concentration is

~ 2600 ppm and

~ 2800 ppm.

~Insert 1 I SR 3.6.7.4 Verify each RS and casing cooling manual, 31 days power operated, and automatic valve in the

~Insert 1 flow path that is not locked, sealed, or I

otherwise secured in position is in the correct position.

SR 3.6.7.5 Verify,each RS and casing cooling pump's In accordance developed head at the flow test point is with the greater than or equal to the required Inservice developed head.

Testing Program North Anna Units 1 and 2 3.6.7-2 Amendments 231/218

RS System 3.6.7 SURVEILLANCE REQUIREMENTS SR 3.6.7.6 SURVEILLANCE Verify on an actual or simulated actuation signal(s):

a. Each RS automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, actuates to the correct position;

b. Each RS pump starts automatically; and

c. Each casing cooling pump starts automati ca11y.

FREQUENCY 18 1fl61'1Hls

'--1lnsert """1--'

SR 3.6.7.7 Verify, by visual inspection, each RS train 18 1fl61'1tn3 containment sump component is not restri cted by debri s and shows no evidence Insert 1 -I of structural distress or abnormal corrosion.

SR 3.6.7.8 Verify each spray nozzle is unobstructed.

Following

~

maintenance which could cause nozzle blockage North Anna Units 1 and 2 3.6.7-3 Amendments 259/239

Chemical Addition System 3.6.8 3.6 CONTAINMENT SYSTEMS 3.6.8 Chemical Addition System LCO 3.6.8 The Chemical Addition System shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

Chemical Addition A.l Restore Chemical 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months System inoperable.

Addition System to OPERABLE status.

B.

Required Action and B.l Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met.

AND B.2 Be in MODE 5.

84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.8.1 Verify each Chemical Addition System 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.

3-l says

'-1lnsert 1

-,Insert 1 I 104 days

'-1lnsert 1 184 dt\\) s

~

Verify chemical addition tank solution volume is

~ 4800 gal and

~ 5500 gal.

Verify chemical addition tank NaOH solution concentration is

~ 12% and

~ 13% by wei ght.

SR 3.6.8.3 SR 3.6.8.2 North Anna Units 1 and 2 3.6.8-1 Amendments 231/212

Chemical Addition System 3.6.8 SURVEILLANCE REQUIREMENTS SR 3.6.8.4 SURVEILLANCE Verify each Chemical Addition System automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

FREQUENCY 18 ffi61'lH13

'-1lnsert 1 SR 3.6.8.5 Verify Chemical Addition System flow from each solutionis flow path.

Insert 1 North Anna Units 1 and 2 3.6.8-2 Amendments 231/212

SURVEILLANCE REQUIREMENTS SURVEILLANCE MSTVs 3.7.2 FREQUENCY SR 3.7.2.1 SR 3.7.2.2

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

Only required to be performed in MODES 1 and 2.

Verify isolation time of each MSTV is

s; 5 seconds.

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

Only required to be performed in MODES 1 and 2.

Verify each MSTV actuates to the isolation position on an actual or simulated actuation signal.

In accordance with the Inservice Testing Program 18 A'lORtI:lS

~Insert 1 North Anna Units 1 and 2 3.7.2-2 Amendments 2dl/212

MFIVs, MFPDVs, MFRVs, and MFRBVs 3.7.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D.

One or more MFPDV D.1 Close or isolate 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months inoperable.

MFPDV.

AND D.2 Verify MFPDV is closed Once per 7 days or isolated.

E.

Two valves in the same E.1 Isolate affected flow 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months flow path inoperable.

path.

F.

Required Action and F.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met.

AND F.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SURVEILLANCE REQUIREMENTS SR 3.7.3.1 SR 3.7.3.2 SURVEILLANCE Verify the isolation time of each MFIV, MFRV, and MFRBV is

~ 6.98 seconds and the isolation time of each MFPDV is

~ 60 seconds.

Verify each MFIV, MFPDV, MFRV, and MFRBV actuates to the isolation position on an actual or simulated actuation signal.

FREQUENCY In accordance with the Inservice Testing Program 18 mOI,th~

~Insert 1 North Anna Units 1 and 2 3.7.3-2 Amendments 231/212

SG PORVs 3.7.4 3.7 PLANT SYSTEMS 3.7.4 Steam Generator Power Operated Relief Valves (SG PORVs)

LCO 3.7.4 Three SG PORV lines shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3, MODE 4 when steam generator is relied upon for heat removal.

ACTIONS CONDITION REQUIRED ACTI ON COMPLETION TIME A.

One required SG PORV A.1 Restore required SG 7 days line inoperable.

PORV line to OPERABLE status.

B.

Two or more required B.1 Restore all but one SG SG PORV lines PORV line to OPERABLE inoperable.

status.

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

Required Action and C.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Ti me not met.

AND C.2 Be in MODE 4 without 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months reliance upon steam generator for heat removal.

SURVEILLANCE REQUIREMENTS SR 3.7.4.1 SR 3.7.4.2 SURVEILLANCE Verify one complete cycle of each SG PORV.

Verify one complete cycle of each SG PORV manual isolation valve.

FREQUENCY North Anna Units 1 and 2 3.7.4-1 Amendments 231/212

ACTIONS AFW System 3.7.5 CONDITION REQUIRED ACTION COMPLETION TIME C.

Required Action and C.l Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time for Condition A AND or B not met.

C.2 Be in MODE 4.

18 hours2.083333e-4 days 0.005 hours 2.97619e-5 weeks 6.849e-6 months OR Two AFW trains inoperable in MODE 1, 2, or 3.

D.

Three AFW trains D.l

NOTE--------

inoperable in MODE 1, LCO 3.0.3 and all 2, or 3.

other LCO Required Actions requiring MODE changes are suspended until one AFW train is restored to OPERABLE status.

Initiate action to Immediately restore one AFW train to OPERABLE status.

E.

Required AFW train E.l Initiate action to Immediately inoperable in MODE 4.

restore AFW train to OPERABLE status.

SURVEILLANCE REQUIREMENTS SR 3.7.5.1 SURVEILLANCE Verify each AFW manual, power operated, and automatic valve in each water flow path, and in both steam supply flow paths to the steam turbine driven pump, that is not locked, sealed, or otherwise secured in position, is in the correct position.

FREQUENCY 31 days

'-1lnsert 1 North Anna Units 1 and 2 3.7.5-2 Amendments 231/212

AFW System 3.7.5 SURVEILLANCE REQUIREMENTS SR 3.7.5.2 SR 3.7.5.3 SR 3.7.5.4 SURVEILLANCE

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

Not required to be performed for the turbine driven AFW pump until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after 2 1005 psig in the steam generator.

Verify the developed head of each AFW pump at the flow test point is greater than or equal to the required developed head.

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

Not applicable in MODE 4 when steam generator is relied upon for heat removal.

Verify each AFW automatic valve that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

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

1. Not required to be performed for the turbine driven AFW pump until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after 2 1005 psig in the steam generator.

2. Not applicable in MODE 4 when steam generator is relied upon for heat removal.

FREQUENCY In accordance with the Inservice Testing Program 18 Rl8RtR5

'-1lnsert 1 Verify each AFW pump starts automatically 18 liio~tli5lnsert 1 I on an actual or simulated actuation signal.

~

SR 3.7.5.5 Verify proper alignment of the required AFW flow paths by verifying flow from the emergency condensate storage tank to each steam generator.

Prior to enteri ng MODE 3, whenever unit has been in MODE 5, 6, or defueled for a cumulative period> 30 days North Anna Units 1 and 2 3.7.5-3 Amendments 231/212

ECST 3.7.6 3.7 PLANT SYSTEMS 3.7.6 Emergency Condensate Storage Tank (ECST)

LCO 3.7.6 The ECST shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3, MODE 4 when steam generator is relied upon for heat removal.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

ECST inoperable.

A.1 Veri fy by 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months administrative means OPERABI LITY of AND Condensate Storage Tank.

Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND A.2 Restore ECST to 7 days OPERABLE status.

B.

Required Action and B.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met.

AND B.2 Be in MODE 4, without 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months reliance on steam generator for heat removal.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.6.1 Verify the ECST contains z 110,000 gal.

12 North Anna Units 1 and 2 3.7.6-1 Amendments 231/212

Secondary Specific Activity 3.7.7 3.7 PLANT SYSTEMS 3.7.7 Secondary Specific Activity LCO 3.7.7 The specific activity of the secondary coolant shall be

~ 0.10 ~Ci/gm DOSE EQUIVALENT 1-131.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION A.

Specific activity not A.l withi n 1imi t.

AND A.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE REQUIRED ACTION Be in MODE 3.

Be in MODE 5.

COMPLETION TIME 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours FREQUENCY SR 3.7.7.1 Verify the specific activity of the secondary coolant is

~ 0.10 ~Ci/gm DOSE EQUIVALENT 1-131.

31 days

~Insert 1 North Anna Units 1 and 2 3.7.7-1 Amendments

~31/212

ACTIONS SW System 3.7.8 CONDITION REQUIRED ACTION COMPLETION TIME D.

Required Actions and D.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Times of Conditions A, AND B or C not met.

D.2 Be in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months E.

Two SW System loops E.1 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months inoperable for reasons other than only two SW AND pumps being OPERABLE.

E.2 Initiate actions to be 13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months in MODE 5.

SURVEILLANCE REQUIREMENTS SR 3.7.8.1 SR 3.7.8.2 SURVEILLANCE

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

Isolation of SW flow to individual components does not render the SW System inoperable.

Verify each SW System manual, power operated, and automatic valve in the flow path servicing safety related equipment, that is not locked, sealed, or otherwise secured in position, is in the correct position.

Verify each SW System automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

FREQUENCY 31 days

'-1lnsert 1 113 R:lQRtI:lS

'-1lnsert 1 SR 3.7.8.3 Verify each SW pump starts automatically on an actual or simulated actuation signal.

18 mOI,th~

'\\

Insert1 I North Anna Units 1 and 2 3.7.8-3 Amendments 231/212

3.7 PLANT SYSTEMS 3.7.9 Ultimate Heat Sink (UHS)

LCO 3.7.9 The UHS shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS UHS 3.7.9 CONDITION A.

UHS inoperable.

SURVEILLANCE REQUIREMENTS A.l AND A.2 REQUIRED ACTI ON Be in MODE 3.

Be in MODE 5.

COMPLETION TIME 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours SURVEILLANCE FREQUENCY SR 3.7.9.1 Verify water level of the Service Water Reservoir is

~ 313 ft mean sea level.

SR 3.7.9.2 Verify average water temperature of the Service Water Reservoir is

~ 95°F.

Insert 1 North Anna Units 1 and 2 3.7.9-1 Amendments 231/212

ACTIONS MCR/ESGR EVS I 3.7.10 CONDITION REQUIRED ACTION COMPLETION TIME E.

(continued)

OR 1/

/

Two required MCR/ESGR EVS trains inoperable during movement of recently irradiated fuel assemblies for reasons other than Condition B.

J F.

Two required MCR/ESGR F.1 Enter LCO 3.0.3.

Immediately EVS trains inoperable in MODE 1, 2, 3, or 4

/f for reasons other than Condition B.

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.7.10.1 Operate each required MCR/ESGR EVS train for 2 10 continuous hours with the heaters operating.

SR 3.7.10.2 Perform required MCR/ESGR EVS filter testing in accordance with the Ventilation Filter Testing Program (VFTP).

SR 3.7.10.3 Not Used FREQUENCY 31 lays

~Insert 1 In accordance with VFTP North Anna Units 1 and 2 3.7.10-3 Amendments 255/236

ACTIONS CONDITION E.

Less than 100% of the E.1 MCR/ESGRACS cooling equivalent to a single OPERABLE MCR/ESGR ACS subsystem available in MODE 1, 2, 3, or 4.

SURVEILLANCE REQUIREMENTS REQUIRED ACTION Enter LCO 3.0.3.

MCR/ESGR ACS 3.7.11 COMPLETION TIME Immediately SURVEILLANCE SR 3.7.11.1 Verify each required MCR/ESGR ACS chiller has the capability to remove the assumed heat load.

FREQUENCY 18 fl'l8I'ltRS SA a STAGGERED TEST Insert 1 North Anna Units 1 and 2 3.7.11-2 Amendments 2dl/212

ECCS PREACS 3.7.12 3.7 PLANT SYSTEMS 3.7.12 Emergency Core Cooling System (ECCS) Pump Room Exhaust Air Cleanup System (PREACS)

LCO 3.7.12 Two ECCS PREACS trains shall be OPERABLE.

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

The ECCS pump room boundary openings not open by design may be opened intermittently under administrative control.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTI ON COMPLETION TIME A.

One ECCS PREACS train A.1 Restore ECCS PREACS 7 days inoperable.

train to OPERABLE status.

B.

Two ECCS PREACS trains B.1 Restore ECCS pump room 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months inoperable due to boundary to OPERABLE inoperable ECCS pump status.

room boundary.

C.

Required Action and C.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met.

AND C.2 Be in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.7.12.1 Operate each ECCS PREACS train for

~ 10 continuous hours with the heaters operating.

FREQUENCY 31 lays

'-1lnsert 1 North Anna Units 1 and 2 3.7.12-1 Amendments 231/212

SURVEILLANCE REQUIREMENTS SURVEILLANCE ECCS PREACS 3.7.12 FREQUENCY SR 3.7.12.2 SR 3.7.12.3 SR 3.7.12.4 SR 3.7.12.5 Actuate each ECCS PREACS train by aligning Safeguards Area exhaust flow and Auxiliary Building Central exhaust flow through the Auxiliary BuildingHEPA filter and charcoal adsorber assembly.

Perform required ECCS PREACS filter testing in accordance with the Ventilation Filter Testing Program (VFTP).

Verify Safeguards Area exhaust flow is diverted and each Auxiliary Building filter bank is actuated on an actual or simulated actuation signal.

Verify one ECCS PREACS train can maintain a negative pressure relative to adjacent areas during post accident mode of operation.

31 says

~Insert 1 In accordance wi th the VFTP 18 ffi6l'lti'lS

~Insert1 18 iiiOlitli5 M

a

~~TEST Insert 1 North Anna Units 1 and 2 3.7.12-2 Amendments 231/212

FBVS 3.7.15 3.7 PLANT SYSTEMS 3.7.15 Fuel Building Ventilation System (FBVS)

LCO 3.7.15 The FBVS shall be OPERABLE and in operation.

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

The fuel building boundary may be opened intermittently under administrative control.

APPLICABILITY:

During movement of recently irradiated fuel assemblies in the fue1 buil ding.

ACTIONS

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

LCO 3.0.3 is not applicable.

CONDITION REQUIRED ACTION COMPLETION TIME A.

FBVS inoperable.

OR FBVS not in operation.

SURVEILLANCE REQUIREMENTS A.l Suspend movement of Immediately recently irradiated fuel assemblies in the fuel buil ding.

SURVEILLANCE FREQUENCY SR 3.7.15.1 Verify the FBVS can maintain a pressure

~ -0.125 inches water gauge with respect to atmospheric pressure.

18 ffie~I9Sr:--~~

"-11nsert 1 North Anna Units 1 and 2 3.7.15-1 Amendments 231/212

Fuel Storage Pool Water Level 3.7.16 3.7 PLANT SYSTEMS 3.7.16 Fuel Storage Pool Water Level LCO 3.7.16 The fuel storage pool water level shall be 2 23 ft over the top of irradiated fuel assemblies seated in the storage racks.

APPLICABILITY:

During movement of irradiated fuel assemblies in the fuel storage pool.

ACTIONS CONDITION A.

Fuel storage pool A.l water level not within 1imi t.

REQU IRED ACTI ON

NOTE---------

LCO 3.0.3 is not applicable.

COMPLETION TIME SURVEILLANCE REQUIREMENTS SURVEILLANCE Suspend movement of Immediately irradiated fuel assemblies in the fuel storage pool.

FREQUENCY SR 3.7.16.1 Verify the fuel storage pool water level is 2 23 ft above the top of the irradiated fuel assemblies seated in the storage racks.

7 eJaY3

~Insert 1 North Anna Units 1 and 2 3.7.16-1 Amendments 231/212

Fuel Storage Pool Boron Concentration 3.7.17 3.7 PLANT SYSTEMS 3.7.17 Fuel Storage Pool Boron Concentration LCO 3.7.17 The fuel storage pool boron concentration shall be

~ 2600 ppm.

APPLICABILITY:

When fuel assemblies are stored in the fuel storage pool.

ACTIONS CONDITION A.

Fuel storage pool boron concentration not within limit.

REQUIRED ACTION

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

LCO 3.0.3 is not applicable.

COMPLETION TIME A.l Suspend movement of Immediately fuel assemblies in the fuel storage pool.

AND SURVEILLANCE REQUIREMENTS A.2 Initiate action to restore fuel storage pool boron concentration to within limit.

Immediately SURVEILLANCE FREQUENCY SR 3.7.17.1 Verify the fuel storage pool boron concentration is within limit.

7 North Anna Units 1 and 2 3.7.17-1 Amendments 231/212

SURVEILLANCE REQUIREMENTS SURVEILLANCE CC System 3.7.19 FREQUENCY SR 3.7.19.1 Verify each CC manual, power operated, and automatic valve in the flow path servicing the residual heat removal system, that is not locked, sealed, or otherwise secured in position, is in the correct position.

31 day:;

'--1lnsert 1 North Anna Units 1 and 2 3.7.19-2 Amendments 231/212

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS SR 3.8.1.1 SR 3.8.1.2 SR 3.8.1.3 SURVEILLANCE Verify correct breaker alignment and indicated power availability for each required offsite circuit.

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

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

2. A modified EDG start involving idling and gradual acceleration to synchronous speed may be used for this SR as recommended by the manufacturer. When modified start procedures are not used, the time, voltage, and frequency tolerances of SR 3.8.1.7 must be met.

Verify each required EDG starts from standby conditions and achieves steady state voltage

~ 3740 V and

~ 4580 V, and frequency ~ 59.5 Hz and

~ 60.5 Hz.

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

1.

EDG 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 EDG at a time.

4. This SR shall be preceded by and immediately follow without shutdown a successful performance of SR 3.8.1.2 or SR 3.8.1.7.

Verify each required EDG is synchronized and loaded and operates for

~ 60 minutes at a load

~ 2500 kW and

~ 2600 kW.

FREQUENCY 7 elays

~Insert 1 31 dtl::Ys

~Insert 1 31 says

~Insert 1 North Anna Units 1 and 2 3.8.1-8 Amendments 231/212

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS SR 3.8.1.4 SR 3.8.1.5 SR 3.8.1.6 SR 3.8.1.7 SR 3.8.1.8 SURVEILLANCE Verify each required day tank contains

~ 450 gal of fuel oil.

Check for and remove accumulated water from each required day tank.

Verify each required fuel oil transfer pump operates to transfer fuel oil from the storage tank to the day tank.

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

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

Verify each required EDG starts from standby condition and achieves

a. In ~ 10 seconds, voltage

~ 3960 V and frequency

~ 59.5 Hz; and

b. Steady state voltage

~ 3740 V and

~ 4580 V, and frequency

~ 59.5 Hz and

~ 60.5 Hz.

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

1. This Surveillance is only applicable to Unit 1.

2. This Surveillance shall not normally be performed in MODE lor 2. However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the unit is maintained or enhanced.

Verify manual transfer of AC power sources from the normal offsite circuit to the alternate required offsite circuit.

FREQUENCY 31 elay:;

~Insert 1 I 92 says

~Jlnsert 1 I 92 elays

~Insert 1 184 elay:;

~Insert 1 -

18 ffi6fltl:lS

~Insert1 North Anna Units 1 and 2 3.8.1-9 Amendments 231/212

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS SR 3.8.1.9 SURVEILLANCE

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

If performed with EDG synchronized with offsite power, it shall be performed at a power factor

~ 0.9. However, 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.

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

a. Following load rejection, the frequency is

~ 66 Hz;

b. Within 3 seconds following load rejection, the voltage is 2 3740 V and

~ 4580 V; and

c. Within 3 seconds following load rejection, the frequency is 2 59.5 Hz and

~ 60.5 Hz.

FREQUENCY 18 m61'ltlcts

~Insert 1 North Anna Units 1 and 2 3.8.1-10 Amendments

~31/~1~

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.8.1.10

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

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

2. This Surveillance shall not normally be performed in MODE 1, 2, 3, or 4.

However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the unit is maintained or enhanced.

Verify on an actual or simulated loss of offsite power signal:

a. De-energization of emergency buses;

b. Load shedding from emergency buses;

c. Each required EDG auto-starts from standby condition and:

1. energizes permanently connected loads in

~ 10 seconds,

2. energizes auto-connected shutdown loads through sequencing timing

relays,

3. maintains steady state voltage Z 3740 V and

~ 4580 V,

4. maintains steady state frequency z 59.5 Hz and

~ 60.5 Hz, and

5. supplies permanently connected and auto-connected shutdown loads for z 5 minutes.

FREQUENCY 18 ffl6l'lti'tS

'-1lnsert 1 North Anna Units 1 and 2 3.8.1-11 Amendments 231/212

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.8.1.11

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

1. All EDG starts may be preceded by prelube period.

2. This Surveillance shall not normally be performed in MODE 1 or 2. However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the unit is maintained or enhanced.

Verify on an actual or simulated Engineered Safety Feature (ESF) actuation signal each LCO 3.8.1.b EDG auto-starts from standby condition and:

a. In ~ 10 seconds after auto-start and during tests, achieves voltage Z 3960 V and frequency z 59.5 Hz;

b. Achieves steady state voltage z 3740 V and

~ 4580 V and frequency z 59.5 Hz and

~ 60.5 Hz;

c. Operates for z 5 minutes;

d. Permanently connected loads remain energized from the offsite power system; and

e. Emergency loads are energized or auto-connected through the sequencing timing relays from the offsite power system.

FREQUENCY 18 mOfltRs

'-1lnsert 1 North Anna Units 1 and 2 3.8.1-12 Amendments 231/212

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.8.1.12

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

This Surveillance shall not normally be performed in MODE 1 or 2. However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the unit is maintained or enhanced.

Verify each required EDG's automatic trips are bypassed on actual or simulated automatic start signals except:

a. Engine overspeed; and

b. Generator differential current.

FREQUENCY 19 ltIefltRs

~Insert 1 North Anna Units 1 and 2 3.8.1-13 Amendments

~31/21~

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.8.1.13

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

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

2. This Surveillance shall not normally be performed in MODE 1 or 2. However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the unit is maintained or enhanced.

3. If performed with EDG synchronized with offsite power, it shall be performed at a power factor

~ 0.9. However, 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.

Verify each required EDG operates for

24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months s

a. For;;:: 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months loaded;;:: 2900 kW and

~ 3000 kW; and

b. For the remaining hours of the test loaded;;:: 2500 kW and

~ 2600 kW.

FREQUENCY 19 1f18RtR5

~Insert 1 North Anna Units 1 and 2 3.8.1-14 Amendments 231/212

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.8.1.14

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

1. This Surveillance shall be performed within 5 minutes of shutting down the EDG after the EDG has operated

~ 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months loaded ~ 2500 kW and

~ 2600 kW or after operating temperatures have stabilized.

Momentary transients outside of load range do not invalidate this test.

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

Verify each required EDG starts and achieves

a. In ~ 10 seconds, voltage

~ 3960 V and frequency ~ 59.5 Hz; and

b. Steady state voltage

~ 3740 V, and

~ 4580 V and frequency ~ 59.5 Hz and

~ 60.5 Hz.

SR 3.8.1.15

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

This Surveillance shall not normally be performed in MODE 1, 2, 3, or 4. However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the unit is maintained or enhanced.

Verify each required EDG:

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.

FREQUENCY 18 FR8RtR5

'-1lnsert 1 18 FR819t19S

'-1lnsert 1 North Anna Units 1 and 2 3.8.1-15 Amendments 231/212

SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.8.1.16

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

This Surveillance shall not normally be performed in MODE 1, 2, 3, or 4. However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the unit is maintained or enhanced.

Verify each required sequencing timing relay is within the design tolerance.

AC Sources-Operating 3.8.1 FREQUENCY North Anna Units 1 and 2 3.8.1-16 Amendments 231/212

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.8.1.17

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

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

2. This Surveillance shall not normally be performed in MODE 1, 2, 3, or 4.

However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the unit is maintained or enhanced.

Verify on an actual or simulated loss of offsite power signal in conjunction with an actual or simulated ESF actuation signal:

a. De-energization of emergency buses;

b. Load shedding from emergency buses; and

c. Each LCO 3.8.1.b EDG auto-starts from standby condition and:

1. energizes permanently connected loads in

~ 10 seconds,

2. energizes auto-connected emergency loads through load sequencing timing

relays,

3. achieves steady state voltage 2 3740 V and

~ 4580 V,

4. achieves steady state frequency 2 59.5 Hz and

~ 60.5 Hz, and

5. supplies permanently connected and auto-connected emergency loads for 2 5 minutes.

FREQUENCY 18 IflORtR5

~Insert1 North Anna Units 1 and 2 3.8.1-17 Amendments 231/212

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.8.1.18

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

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

Verify when started simultaneously from standby condition, each LCO 3.8.1.b EDG achieves:

a. in

~ 10 seconds, voltage 2 3960 V and frequency 2 59.5 Hz; and

b. steady state voltage 2 3740 V and

~ 4580 V, and frequency 2 59.5 Hz and

~ 60.5 Hz.

FREQUENCY 10 Yliliirs

'-1'nsert 1 North Anna Units 1 and 2 3.8.1-18 Amendments 231/212

Diesel Fuel Oil and Starting Air 3.8.3 ACTIONS CONDITION F.

Required Action and F.1 associated Completion Time not met.

OR One or more EDGs diesel fuel oil or starting air subsystem not within limits for reasons other than Condition A, S, C, D, or E.

SURVEILLANCE REQUIREMENTS REQUIRED ACTION Declare associated EDG(s) inoperable.

COMPLETION TIME Immediately SURVEILLANCE FREQUENCY SR 3.8.3.1 SR 3.8.3.2 SR 3.8.3.3 SR 3.8.3.4 Verify fuel oil inventory

~ 90,000 gal.

Verify fuel oil properties of new and stored fuel oil are tested in accordance with, and maintained within the limits of, the Diesel Fuel Oil Testing Program.

Verify each EDG air start receiver pressure is

~ 175 psig.

Check for and remove accumulated water from each stored fuel oil storage tank.

31 eays

~

"-11nsert 1 I In accoraance wi th the Di esel Fuel Oil Testing Program 31 says

~Insert 1 I

§~ days

~Insert 1 I North Anna Units 1 and 2 3.8.3-3 Amendments 254/235

DC Sources-Operating 3.8.4 ACTIONS CONDITION D.

NOTE----------

D.1 Separate Condition entry is allowed for each DC subsystem.

One or more required LCO 3.8.4.c DC electrical power subsystem(s) inoperable.

SURVEILLANCE REQUIREMENTS REQUIRED ACTION Declare associated shared component(s) inoperable.

COMPLETION TIME Immediately SURVEILLANCE FREQUENCY SR 3.8.4.1 SR 3.8.4.2 SR 3.8.4.3 Verify for each required Station and EDG battery, terminal voltage is

~ 129 V on float charge.

Verify for each required Station and EDG battery, there is no visible corrosion at battery terminals and connectors.

OR Verify battery connection resistance is

~ 1.5E-4 ohm for inter-cell connections,

~ 1.5E-4 ohm for inter-rack connections,

~ 1.5E-4 ohm for inter-tier connections, and

~ 1.5E-4 ohm for terminal connections.

Verify for each required Station and EDG battery, cells, cell plates, and racks show no visual indication of physical damage or abnormal deterioration that could degrade battery performance.

7 says

~Insert 1 92 eays

~Insert 1"'"

18 ffi81'1tAS

~Insert 1-North Anna Units 1 and 2 3.8.4-2 Amendments 231/212

DC Sources-Operating 3.8.4 SURVEILLANCE REQUIREMENTS SR 3.8.4.4 SR 3.8.4.5 SR 3.8.4.6 SR 3.8.4.7 SURVEILLANCE For each required Station and EDG battery, remove visible terminal corrosion, verify battery cell to cell and terminal connections are clean and coated with anti-corrosion material.

Verify for each required Station and EDG battery, connection resistance is

~ 1.5E-4 ohm for inter-cell connections,

~ 1.5E-4 ohm for inter-rack connections,

~ 1.5E-4 ohm for inter-tier connections, and

~ 1.5E-4 ohm for terminal connections.

Verify each required Station battery charger supplies

~ 270 amps at

~ 125 V for

~ 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

Verify each required EDG battery charger supplies

~ 10 amps at

~ 125 V for

~ 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

FREQUENCY 18 1fI0RtRS

'-1lnsert 1 18 iiiOiitliS

'-1lnsert 1 -

18 months

'-1lnsert 1..,

18 mOI,tl,s

'-1lnsert 1 North Anna Units 1 and 2 3.8.4-3 Amendments 231/212

DC Sources-Operating 3.8.4 SURVEILLANCE REQUIREMENTS SR 3.8.4.8 SR 3.8.4.9 SURVEILLANCE

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

1. The modified performance discharge test in SR 3.8.4.9 may be performed in lieu of the service test in SR 3.8.4.8.

2. The performance discharge test in SR 3.8.4.9 may be performed in lieu of the service test in SR 3.8.4.8 ~

~Yery eO mSAtAs.

3. This Surveillance shall not normally be performed in MODE 1, 2, 3, or 4.

However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the unit is maintained or enhanced.

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

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

This Surveillance shall not normally be performed in MODE 1, 2, 3, or 4 for Station batteries. However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the unit is maintained or enhanced.

Verify for each required Station and EDG battery, capacity is

~ 80% of the manufacturer1s rating when subjected to a performance discharge test or a modified performance discharge test.

FREQUENCY 18 ffi~

. '-f-:-ln-s-ert~1"""1 eO mSAtRs AND ~Insert 1 18 months when battery shows degradation or has reached 85%

of expected 1ife North Anna Units 1 and 2 3.8.4-4 Amendments 231/212

Battery Cell Parameters 3.8.6 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

(continued)

A.3 Restore battery cell 31 days parameters to Table 3.8.6-1 Category A and B 1imits.

B.

Required Action and B.1 Declare associated Immediately associated Completion battery inoperable.

Time of Condition A not met.

OR One or more Station batteries with average electrolyte temperature of the representative cells

< 60°F.

OR One or more Station or EDG batteries with one or more battery cell parameters not within Table 3.8.6-1 Category C values.

SURVEILLANCE REQUIREMENTS SR 3.8.6.1 SURVEILLANCE Verify for each required Station and EDG battery cell parameters meet Table 3.8.6-1 Category A limits.

FREQUENCY 7 clays

'-1lnsert 1 North Anna Units 1 and 2 3.8.6-2 Amendments 231/212

Battery Cell Parameters 3.8.6 SURVEILLANCE REQUIREMENTS SR 3.8.6.2 SR 3.8.6.3 SURVEILLANCE Verify for each required Station and EDG battery cell parameters meet Table 3.8.6-1 Category B limits.

Verify average electrolyte temperature of representative cells for each required Station battery is

~ 60°F.

FREQUENCY 92 06::) 5 AND ~Insert 1 Once within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after a battery discharge

< 110 V AND Once within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after a battery overcharge

> 150 V 92 06::)5

~Insert 1 North Anna Units 1 and 2 3.8.6-3 Amendments 231/212

ACTIONS Inverters-Operating 3.8.7 CONDITION REQUIRED ACTI ON COMPLETION TIME B.

One or more inverters B.1

NOTE--------

required by Enter applicable LCO 3.8.7.b Conditions and inoperable.

Required Actions of LCO 3.8.9, IIDistribution Systems-Operating ll with any vital bus de-energized.

Declare associated 7 days shared components inoperable.

C.

Required Action and C.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition A AND not met.

C.2 Be in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.7.1 Verify correct inverter voltage and alignment to required AC vital buses.

7 Insert 1 North Anna Units 1 and 2 3.8.7-2 Amendments 253/234

SURVEILLANCE REQUIREMENTS SURVEILLANCE Inverters-Shutdown 3.8.8 FREQUENCY SR 3.8.8.1 Verify correct inverter voltage and alignments to required AC vital buses.

7 North Anna Units 1 and 2 3.8.8-2 Amendments 2al/212

Distribution Systems-Operating 3.8.9 ACTIONS CONDITION REQUIRED ACTI ON COMPLETION TIME F.

NOTE----------

F.l Declare associated Immediately Separate Condition shared components entry is allowed for inoperable.

each AC vital subsystem.

One or more required LCO 3.8.9.b AC vital electrical power distribution subsystem(s) inoperable.

G.

Required Action and G.l Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time for Condition A, AND B, or C not met.

G.2 Be in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months H.

Two or more H.l Enter LCO 3.0.3.

Immediately LCO 3.8.9.a electrical power distribution subsystems inoperable that result in a loss of safety function.

SURVEILLANCE REQUIREMENTS SR 3.8.9.1 SURVEILLANCE Verify correct breaker alignments and voltage to required AC, DC, and AC vital bus electrical power distribution subsystems.

FREQUENCY 7 says

~Insert 1 North Anna Units 1 and 2 3.8.9-3 Amendments

~3/2J4

ACTIONS Distribution Systems-Shutdown 3.8.10 CONDITION REQUIRED ACTION COMPLETION TIME A.

(continued)

SURVEILLANCE REQUIREMENTS A.2.4 Initiate actions to Immediately restore required AC, DC, and AC vital bus electrical power distribution subsystems to OPERABLE status.

AND A.2.5 Declare associated Immediately required residual heat removal subsystem(s) inoperable and not in operation.

SURVEILLANCE SR 3.8.10.1 Verify correct breaker alignments and voltage to required AC, DC, and AC vital bus electrical power distribution subsystems.

FREQUENCY 7 daYs

'-1lnsert 1 North Anna Units 1 and 2 3.8.10-2 Amendments 231/212

Boron Concentration 3.9.1 3.9 REFUELING OPERATIONS 3.9.1 Boron Concentration LCO 3.9.1 Boron concentrations of the Reactor Coolant System (RCS), the refueling canal, and the refueling cavity shall be maintained within the limit specified in the COLR.

APPLICABILITY:

MODE 6.

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

Only applicable to the refueling canal and refueling cavity when connected to the RCS.

ACTIONS CONDITION A.

Boron concentration not within limit.

SURVEILLANCE REQUIREMENTS A.l AND A.2 AND A.3 REQUIRED ACTI ON Suspend CORE All ERATIONS.

Suspend positive reactivity additions.

Initiate action to restore boron concentration to withi n 1imi t.

COMPLETION TIME Immediately Immediately Immediately SURVEILLANCE FREQUENCY SR 3.9.1.1 Verify boron concentration is within the limit specified in the COLR.

72 North Anna Units 1 and 2 3.9.1-1 Amendments 231/212

Nuclear Instrumentation 3.9.3 SURVEILLANCE REQUIREMENTS SR 3.9.3.1 SR 3.9.3.2 SURVEILLANCE Perform CHANNEL CHECK.

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

Neutron detectors are excluded from CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION.

FREQUENCY North Anna Units 1 and 2 3.9.3-2 Amendments 231/212

Containment Penetrations 3.9.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.4.1 SR 3.9.4.2 Verify each required containment penetration is in the required status.

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

Not required to be met for containment purge and exhaust valve(s) in penetrations closed to comply with LCO 3.9.4.c.1.

7 Verify each required containment purge and exhaust valve actuates to the isolation position on manual initiation.

18 ffi81'ltAS

~Insert 1 North Anna Units 1 and 2 3.9.4-2 Amendment 231/~1~

ACTIONS RHR and Coolant Circulation-High Water Level 3.9.5 CONDITION A.

(continued)

A.4 AND REQUIRED ACTION Close equipment hatch and secure with four bolts.

COMPLETION TIME 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months SURVEILLANCE REQUIREMENTS A.5 Close one door in each 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months installed air lock.

AND A.6.1 Close each penetration 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months providing direct access from the containment atmosphere to the outside atmosphere with a manual or automatic isolation valve, blind flange, or

~quivalent.

OR A.6.2 Verify each 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months penetration is capable of being closed by an OPERABLE Containment Purge and Exhaust Isolation System.

SR 3.9.5.1 SURVEILLANCE Verify one RHR loop is in operation and circulating reactor coolant at a flow rate of

~ 3000 gpm.

FREQUENCY 12 Re~l"S

'--1lnsert 1 North Anna Units 1 and 2 3.9.5-2 Amendments 231/212

RHR and Coolant Circulation-Low Water Level 3.9.6 ACTIONS CONDITION REQUIRED ACTI ON COMPLETION TIME B.

(continued)

SURVEILLANCE REQUIREMENTS B.5.2 Verify each 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months penetration is capable of being closed by an OPERABLE Containment Purge and Exhaust Isolation System.

SR 3.9.6.1 SR 3.9.6.2 SURVEILLANCE Verify one RHR loop is in operation and circulating reactor coolant at a flow rate of:

a.

~ 3000 gpm, or b.

~ 2000 gpm if RCS temperature

~ 140°F and time since entry into MODE 3

~ 100 hours0.00116 days 0.0278 hours 1.653439e-4 weeks 3.805e-5 months .

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

Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after a required RHR pump is not in operation.

Verify correct breaker alignment and indicated power available to the required RHR pump that is not in operation.

FREQUENCY 1z Ilotl' 5

~Insert 1 7 gays

~Insert 1 North Anna Units 1 and 2 3.9.6-3 Amendments 231/212

Refueling Cavity Water Level 3.9.7 3.9 REFUELING OPERATIONS 3.9.7 Refueling Cavity Water Level LCO 3.9.7 Refueling cavity water level shall be maintained 2 23 ft above the top of reactor vessel flange.

APPLICABILITY:

During movement of irradiated fuel assemblies within containment.

ACTIONS CONDITION A.

Refueling cavity water A.l level not within 1imi t.

SURVEILLANCE REQUIREMENTS REQUIRED ACTION Suspend movement of irradiated fuel assemblies within containment.

COMPLETION TIME Immediately SURVEILLANCE FREQUENCY SR 3.9.7.1 Verify refueling cavity water level is 2 23 ft above the top of reactor vessel flange.

24~

"---lr:"'"1n-s-ert~1-North Anna Units 1 and 2 3.9.7-1 Amendments 231/212

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.16 e.

The quantitative limits on unfiltered air inleakage into the MCR/ESGR envelope. 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 design basis accident consequences. Unfiltered air inleakage limits for hazardous chemicals must ensure that exposure of MCR/ESGR envelope 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 MCR/ESGR envelope habitability, determining MCR/ESGR envelope unfiltered inleakage, and measuring MCR/ESGR envelope pressure and assessing the MCR/ESGR envelope boundary as required by paragraphs c and d, respectively.

Iinsert2 rl North Anna Units 1 and 2 5.5-17 Amendments 252/232

ML100900163

Contents

Text

1.0 DESCRIPTION

2.0 ASSESSMENT

3.0 REGULATORY ANALYSIS

4.0 ENVIRONMENTAL CONSIDERATION

5.0 REFERENCES

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ML100900163

Text

1.0 DESCRIPTION

2.0 ASSESSMENT

3.0 REGULATORY ANALYSIS

4.0 ENVIRONMENTAL CONSIDERATION

5.0 REFERENCES

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